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POLITECNICO DI MILANO
Scuola di Ingegneria Industriale e dell’Informazione
Corso di Laurea in Ingegneria Energetica
Shale gas in Europe
possibilities and challenges for the natural gas market
Supervisor
Prof. Fabio Inzoli
Correlator
Prof. Roberto Carnicer
(Universidad Austral, BA)
Author
Gatti Leandro Matricola
801063
Academic Year 2014-2015
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To my family,
because none of my achievement
would have been possible
without them
“The Stone Age did not end when mankind run out of stones,
likewise the Oil Age will end long before we run out of oil”
Ahmed Zaki Yaman, Saudi Arabian Petroleum Minister
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1 Abstract
In the last two decades, several significant development contributed in modifying the global energy
scenario; however, none of these had the same impact as the US shale gas revolution. Recent
technological innovation made available large reserves of natural gas held within shale rocks
enormously increased UD domestic production making them pass the foreseen biggest gas importer
to the largest world producing country. This domestic surge in production of natural gas led to
tremendous benefits for the US on both the economy and US CHG emission. This authentic revolution
arouse enormous success in other country, including Europe, who invested in their domestic shale
source in order to replicate the US model increasing internal production, enhancing they energy
security and obtaining a cheap energy source. The US revolution, however, has been the results of an
ongoing process and it will be unlikely replicate elsewhere, especially in Europe where market
structure and energy policies greatly differs from the US ones. This works aim in giving a brief but
exhaustive description of what had been the shale gas revolution and the step that led to this result. In
order to understand the complexity and the controversies involved shale gas would be described from
generation to extraction and processing with particular emphasis on the environmental impact. The
main difference between the union and the US will be asses in order to underline the potential benefits
of shale extraction for the domestic gas market but, mostly, the challenges that have to be faced in
order to create an unconventional gas industry in Europe.
Key Words: natural gas, unconventional hydrocarbon, shale gas, hydraulic fracturing, environmental
impact, gas market
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2 Sommario
Gli ultimi due decenni hanno visto numerosi cambiamenti nello scenario energetico global.
Nessuno di questi ha però avuto la portata della cosiddetta rivoluzione dello “shale gas” negli Stati
Uniti. Recenti sviluppi tecnologici hanno consentito l’estrazione di gas da questi depositi non
convenzionali; grazie allo shale gas gli Stati Uniti sono passati in meno di un decennio da i futuri
maggiori importatori di gas al primo paese produttore al mondo. Il rapidissimo incremento di
produzione di gas da scisti ha avuto un notevole impatto sull’economia statunitense e sulle emissioni
di gas climalteranti. Questa vera e propria rivoluzione ha, prevedibilmente, suscitato enorme interesse
in molti altri paesi, tra cui l’Europa, disposti a investire nel sfruttamento dei depositi di shale per
replicare il boom statunitense ottenendo così una fonte di energia a basso prezzo e aumentando la loro
sicurezza energetica. La rivoluzione statunitense però è stata il risultato di una lunga fare di
sperimentazione e numerosi fattori ne hanno influenzato la riuscita garantendone il risultato; per
questa ragione è improbabile che lo stesso boom possa essere ripetuto altrove. Lo scopo di questo
lavoro è di fornire una descrizione sommaria ma quanto più esaustiva possibile di quello che è stata
la shale gas revolution sottolineando tutti I fattori che hanno contribuito al risultato. Per comprendere
l’intrinseca complessità e le controversie legate al processo lo shale gas verrà descritto dalla sua genesi
al estrazione con particolare riferimento alle tematiche ambientali. Infine si sottolineando le principali
differenze tra stati uniti ed Europa in modo da comprendere I potenziali benefici sul mercato interno
del gas e, soprattutto, le sfide che dovranno essere affrontate per sviluppare un estrazione di gas non
convenzionale in Europa.
Parole Chiave: gas naturale, idrocarburi non convenzionali, shale gas, fratturazione idraulica, impatto
ambientale, mercato gas naturale
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Index of Contents
Abstract .................................................................................................................................................. 5 Sommario ............................................................................................................................................... 7 Index of Contents .................................................................................................................................... 9 Introduction .......................................................................................................................................... 15 Introduction to Natural Gas ................................................................................................................... 17
1.1. What is natural gas? .............................................................................................................................. 18 1.1.1. Composition of Natural Gas ....................................................................................................... 18 1.1.2. Natural gas genesis..................................................................................................................... 19 1.1.3. Formation of a gas reservoir ...................................................................................................... 20 1.2. Natural gas final uses ............................................................................................................................ 21 1.2.1. Residential and commercial uses ............................................................................................... 21 1.2.2. Industrial uses ............................................................................................................................ 21 1.2.3. Power generation ....................................................................................................................... 21 1.1.4. Transportation ............................................................................................................................ 22 1.3. Natural gas environmental benefits ...................................................................................................... 23 1.4. Natural gas global consumption ............................................................................................................ 25 1.5. Natural gas global reserves ................................................................................................................... 26
Natural gas industry and market ............................................................................................................ 29 2.1. Overview of the natural gas supply chain ............................................................................................. 29 2.1.1. Upstream .................................................................................................................................... 30 2.1.2. Midstream .................................................................................................................................. 30 2.2. Gas transportation ................................................................................................................................ 32 2.3. Natural gas market structure ................................................................................................................ 32 2.3.1. Gas market characteristics ........................................................................................................ 34 2.4. The European model: the US gas market .............................................................................................. 36 2.4.1. Physical and financial market .................................................................................................... 37
The European gas market ...................................................................................................................... 39 3.1. European energy consumption ............................................................................................................. 40 3.2. European energy dependence .............................................................................................................. 44 3.3. European gas market............................................................................................................................. 46 3.3.1. European gas consumption ....................................................................................................... 48 3.3.2. Natural gas production .............................................................................................................. 51 3.3.3. Extra European Imports ............................................................................................................ 52 3.3.4 The European gas network ......................................................................................................... 54 3.4. Future scenario ...................................................................................................................................... 58
Shale Gas, an Unconventional Global Resource ...................................................................................... 61 4.1. Unconventional gas ............................................................................................................................... 61 4.2. Estimation of Global Resources ............................................................................................................. 64 4.3. Shale Gas ............................................................................................................................................... 66 4.3.1. Shale gas generation process .................................................................................................... 67 4.3.2. Resource estimation and global availability .............................................................................. 72 4.4. Shale gas extraction process ................................................................................................................. 74 4.4.1. Exploratory phase ...................................................................................................................... 74 4.4.2. Site preparation ......................................................................................................................... 74 4.4.3. Well drilling and completion ..................................................................................................... 75
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4.4.4. Hydraulic fracturing ........................................................................................................................ 78 4.4.5. Shale gas production ...................................................................................................................... 82 Global impact of the US Energy Revolution ............................................................................................ 85 5.2. The Shale Gas Revolution ...................................................................................................................... 86 5.3. Impact on the global LNG market and on European gas pricing .......................................................... 90 5.4. Shale Gas in Europe............................................................................................................................... 91 5.4.1. Shale gas basin characterization ............................................................................................... 93 5.4.2. Exploration activities in Europe ................................................................................................ 96 5.5. Environmental Impact of shale gas recovery ....................................................................................... 98 5.5.1. Impact on water resources ....................................................................................................... 99 5.5.2. Hydraulic fracturing water cycle ............................................................................................. 101 5.5.3. Water consumption ................................................................................................................ 103 5.5.4. Induced Seismicity .................................................................................................................. 105 5.5.5. Land Consumption and Spatial Constraints ............................................................................ 106 5.5.6. Greenhouse-gas Emission of Shale Gas Recovery .................................................................. 107 The European way to shale gas ............................................................................................................ 109 6.1. The shale dream: the case of Poland .................................................................................................. 110 6.1.1. The development of Baltic Basin ............................................................................................ 111 6.2. US success factors and European limits .............................................................................................. 113 6.2.1. Technology development ....................................................................................................... 114 6.2.2. Federal and State policies ....................................................................................................... 115 6.2.3. E&P regulation ........................................................................................................................ 116 6.2.4. Access to land and infrastructure ........................................................................................... 116 6.3. The European way to shale gas .......................................................................................................... 117 6.3.1. The European model .............................................................................................................. 118 6.3.2. Evolution rather than Revolution ........................................................................................... 118 General conclusions and implications for European gas market ............................................................ 121 References ...................................................................................................................................................... 125
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Index of figure
Figure 1.1 - Oil and gas temperatures related to depth of burial………………….……………….……............5
Figure 1.2 - Formation of an oil and gas eservoir……………………………......................................................6
Figure 1.3 - Scheme of a CCGT power plant………………………………………..…….……………...……..8
Figure 1.4 - Equivalent carbon dioxide emission for different electricity generation……………..……............10
Figure 1.5 - Historical gas consumption per region………………………………………………………….....11
Figure 1.6 - Forecast on natural gas consumption per world region……………………….…….……………..12
Figure 1.7 - Natural gas proven reserves by region………………………………………………………….…13
Figure 2.1 - Natural gas supply chain……………………………………………...……….……………….….16
Figure 2.2 - Natural gas midstream facilities………………………………………………………...…….…..17
Figure 2.3 - Major gas trade flow worldwide in 2014……………………………………………………….…18
Figure 2.4 - Gas price in major distinct market…………………………………………………..….…………18
Figure 2.5 - Major gas market characteristics……………………………………………...…....……….…….19
Figure 3.1 - Energy balance………………………………………………………………...………….….…...26
Figure 3.2 - European primary energy consumption for 2013………………………………………………….28
Figure 3.3 - European final energy consumption (MToe) for 2013……………………………….…….…...…29
Figure 3.4 - European power generation (2013)…………………………………………………….. ……...…30
Figure 3.5 - European energy dependency on fossil fuel…………………………………………………….…31
Figure 3.6 - European dependency on natural gas imports……………………………………………..………32
Figure 3.7 - European historical gas series………………………………………………………………..……33
Figure 3.8 - Eu-28 gas consumption breakdown…………………………………………………………...…..34
Figure 3.9 - Gas consumption breakdown for final use……………………………………………………...…34
Figure 3.10 - Historical breakdown of European gas consumption…………………………………………….35
Figure 3.11 - Electricity production with gas-fired power plant (1985 - 2012)……………………………. …..36
Figure 3.12 - Breakdown of EU-28 supplies…………………………………………………...………………37
Figure 3.13 - Natural gas production in EU-28 (1981-2013)……………………………………………….. …37
Figure 3.14 - Extra-EU imports…………………………………………………………...…………………...38
Figure 3.15 - Natural gas imports, breakdown by importer…………………………………………………….39
Figure 3.16 - EU imports of LNG, a) exporting country b) importing country………………………................40
Figure 3.17 - Map of European gas network…………………………………………………………...………42
Figure 3.18 - a) Maps of Gazprom import price in Europe b) price and transportation costs in the US hub
($/mBTU)………………………………………………………………….. …………………………………44
Figure 3.19 – Breakdown of European gas demand 2010 – 2035……………………………………………..45
Figure 4.1 - Schematic cross-section of general types of oil and gas resources…………………………...……49
Figure 4.2 - The natural gas resource triangle……………………………………………………………...…..50
Figure 4.3 - World natural gas resources classified by typology and world region………………………….…51
Figure 4.4 - Black shale rock and shale outcrop deposits……………………………………………………....52
Figure 4.5 - The process of hydrocarbon generation trough thermal maturation of source rock………………..53
Figure 4.6 - Shale rock turning into a gas-shale source rock………………………………………………….54
Figure 4.7 - a) Van Krevelen diagram, b) scheme of hydrocarbon generation and yields…………………….56
Figure 4.8 - Adsorption Isotherm, Gas Content vs. Pressure…………………………………………………...57
Figure 4.9 - Schematic representation of the steps used in the geological based approach…………………...58
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Figure 4.10 -World estimate natural gas resource…………………………………………………………..…59
Figure 4.11 - Drilling site in the Marcellus shale, Pennsylvania………………………………………...…..…61
Figure 4.12 - Casing and cement job in a shale well, schematic and cross section……………………...………63
Figure 4.13 - Horizontal shale gas wells, cluster configuration……………………………………………..….63
Figure 4.14 - a) Hydraulic fracturing equipment in a shale well in the Marcellus shale b) Schematic illustration
of the hydraulic fracturing process……………………………………………………………………………..64
Figure 4.15 - Typical volumetric composition of fracturing fluid……………………………………...………65
Figure 4.16 - a) Microseismic event location for hydraulic fracture treatment b) Fracstage diagram…………67
Figure 4.17 - Production site of a shale well in the Marcellus area………………………………………..……68
Figure 4.18 - Shale gas well production profile, Haynesville Shale Louisiana…………………………………69
Figure 5.1 - Monthly natural gas production and henry Hub spot price…………………………………..…….72
Figure 5.2 - U.S. dry shale gas production per basin………………………………………………………...…74
Figure 5.3 - US electricity production per source and CO2 associated emission…………….…………………75
Figure 5.4 - a) European oil and gas price b) European import of LNG……….………………………….……77
Figure 5.5 - European shale gas basin with resource estimate……………………………………………….…78
Figure 5.6 - European regulation regarding shale gas exploration and hydraulic fracturing…………….……..83
Figure 5.7 - a) The “water tap on fire” clip from Gasland b) Tone of media coverage of shale gas development
in the USA…………………………………………………………….………………………………....…...84
Figure 5.8 - Marcellus Mapped Frac Treatment………………………………………………...………….......86
Figure 5.9 - Hydraulic fracturing water……………………………………………………………..…..…..…88
Figure 5.10 - Water consumption in electricity generation………………………………………………….....90
Figure 5.11 - Frequency vs. magnitude for the review event of induced seismicity……………………………91
Figure 5.12 - a) Map of Texas, population density b) Shale wells drilled in the area in 2010……………...….92
Figure 5.13 - Comparison of the life-cycle emission for the production of electricity………………………….93
Figure 6.1 - Process improvement made by Southwestern Energy from 2007 to 2011…………………….…98
Figure 6.2 - Growth in the number of horizontal wells and customized technologies…………………..…….100
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Index of tables
Table 1.1 – Chemical composition of natural gas………………………………………..………...…4
Table 2.2 – Specific energy, energy density and yielded CO2 for different fossil fuels…………...….10
Table 1.3 – Air pollutant emissions from fossil fuels steady combustion…………………………...10
Table 4.1 – Types of Kerogen and their hydrocarbon potential…………………………………..…..55
Table 5.1 – Eastern Europe prospective shale basin……………………………….…………………80
Table 5.2 – Western Europe prospective shale basin……………………………….………………...80
Table 5.3 – Comparison of Eu-28 shale gas estimates with conventional reserves………………..….81
Table 5.4 – Water consumption during fuel extraction and processing………………………….….90
Table 6.1 – Shale gas in Europe and the US – Revolution vs Evolution………………………….…105
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4 Introduction
If we consider human history, we can gather that all major steps forward in progress can be put
down to energy exploitation and transformation. Since the beginning of human history, major
advances in energy usage and transformation led to an improvement in humanity lifestyle. The last
two centuries have witnessed Incredibles technological and life quality improvements; all of which
based on the exploit of fossil fuels.
Fossil fuels are the engine that powers our society but their consumption has led to environmental
problems, from local pollution to global warming issues: current consumption trends are not
sustainable in the long run. Despite the recent progress in renewable energy production, these
technologies are far from being able to fulfill global energy demand. Despite the optimism and the
high potential renewables still have a long development phase ahead.
However, there is an energy source that could reduce emissions while acting as “bridge fuel”
towards a greener future: natural gas. Natural gas is the simplest between all fossil fuels; it is exploited
in all the final uses (from residential heating to power generation) guaranteeing superior
environmental and technological performance compared with coal and oil derivatives.
Despite its versatility and its environmental performance, utilization of natural gas is still
constrained by its nature. A gaseous fuel is more complex to handle, transport and store with respect
to a liquid (oil and derivatives) or solid fuel (coal). Natural gas extraction is subjected to an economic
analysis based on the distance between the field and the final market; for most of its industrial history,
its transportation and distribution costs have been higher than final market price.
This constrain prevented natural gas to evolve in a unique global market (as the case of oil),
generating many regional markets with differences in traded volumes, pricing scheme and final price.
The lack of a connection created regional market where a bunch of exporting country enjoy a nearly
monopolistic with excessive influence over volumes trade and market price.
High market control is particularly evident in the European1 market, which relies mainly on three
suppliers (Russia, Norway and Algeria) some of which (Russia) are de facto the only supplier of some
member countries. This high dependency has been particularly aggravated by the recent geopolitical
events as the war in Ukraine with the growing tensions between western governments and Russia and
the increasing instability of North African and Middle-Eastern countries.
The recent boom of gas extraction from unconventional shale formation in the US aroused
significant interest in Europe as a way to increase domestic gas production reducing import
dependency and increasing energy security. In 2000, the US, after a thirty-year decline in gas
production, were foreseen to became the world biggest gas importer; the boom of shale gas totally
overturned this scenario. This sudden increase in natural gas production has been defined a
“revolution” and has turned the US from an importer country to a potential exporter.
1 In all this work “European”, “Eu” and “Europe” would be used as synonyms referring to the European Union member countries and not as the geographical Europe.
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Predictably, the US experience raised interest for this source in other countries worldwide; shale
basins, in fact, are much more evenly distributed on the globe than conventional gas deposits.
Europe has some promising shale basins, many located in Eastern Europe countries in country where
the high dependency from Russia poses serious threat to energy security and political stability.
Shale gas extraction is still a widely debated topic within the European Union mostly because of
its extraction process (hydraulic stimulation of “fracking”); member countries, as general public, are
divide between the enthusiast those willing to start a national production and the “opponents”, which
placed a ban on the utilization of this technology. To date, shale gas exploration started in only in
Poland and the results have been little disappointing and no commercial production has yet started.
The reason behind this “failure” has to be found can be found in the differences existing between
Europe and the US in terms shale formation characteristics, geological knowledge and market
conditions, which makes the US development model only partially applicable. Hence understanding
different factors that triggered the American shale boom are essential to understand the European
potential and the challenges that will have to face in the development of the
“European way” to shale extraction.
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Chapter 1
Introduction to Natural Gas
For more than a century natural gas had been consider as a sort of lower quality oil-surrogate.
Natural gas is often found associated with oil in conventional deposit; but, contrary to oil, its extraction
depends on the distance between field and final market. During most of its industrial life, its
commercial value was lower than its transportation costs and burned (flared) or liberated in the
atmosphere (vented) on site. Things changed in the seventies after the “oil crises” when it was
extensively used instead of oil-based fuels. The increased consumption of the last decade, led natural
gas to become the third energy source employed worldwide. Between all energy sources, natural gas
is experiencing the fastest growing rate and has the most promising future.
The main component of natural gas is methane (CH4), the simplest between all the hydrocarbons.
Its combustion process releases the lowest amount of carbon dioxide of all fossil fuel thus making
natural gas the “greenest” non-renewable source. This rate of increasing consumption is expected to
continue in the next years both in developing countries and in industrialized ones. The development
of African, Middle-Eastern and Central-Asia countries will increase the number of final costumers
with access to the gas networks. In industrialized countries the increasingly stringent environmental
policies. On the other hand, in the most industrialized countries the stringent environmental policies
could led natural gas in becoming more than coal for power generation or oil products for road
transport.
Despite its wide final uses and its environmental benefits, natural gas global consumption is still
constrained by some factors: its gaseous nature make him difficult to transport and store and
technologies employed are more costly with respect to other fuels. For the same energy content natural
gas occupies a volume a thousand times greater than crude oil; this is why transporting natural gas
from the wellhead to the final market has not been feasible or economically convenient for most of
the last century. Natural gas tend to be exploited as close as possible to production site: only one third
of the worldwide produced gas is exported.
Transportation rigidity limits the number of potential importers: high dependence by a restrict
number of supplier poses some energy security risks. Gas producer have a higher influence and
political power with respect to oil ones because their costumers have fewer supply alternatives. This
is the case of the European Union where almost all the gas imported come from just three supplier
(Russia, Algeria and Norway) and it is sold with very rigid contracts. In the end, an increasing
employment of natural gas presents several benefits and some major constrains; the evolution of those
contrasting elements in the next future will determine the possibility for natural gas to become the
first energy source worldwide overcoming oil and establishing the “end” of the oil age.
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1.1. What is natural gas?
Natural gas is composed primarily of methane, but also includes various amounts of other short-
chained alkanes and a percentage of inert gas or pollutants. Natural gas generates following the
chemical degradation of organic matter, either because of anaerobic bacteria (biogenic gas) or because
of a series of chemical reaction happening in a high temperature and pressure environment deep in the
earth crust (thermogenic gas). Almost all the natural gas consumed worldwide has a thermogenic
origin and is extracted from deep underground accumulation associated with oil (associated gas) or
alone (dry gas). Biogenic gas, on the contrary, is found in much smaller amount at a shallow depth as
a result of the burying of old swamp or marsh (hence the name swamp gas). It can also be produced
with specifically design processes of organic fermentation; in this case is called “biogas” and it is
considered a renewable source.
1.1.1. Composition of Natural Gas
Natural gas is a hydrocarbon mixture consisting of light saturated paraffin2 (like
methane and ethane) but it might also contain some heavier hydrocarbons; ranging from propane to
hexane.
Table 1.1 – Chemical composition of natural gas (Mokhatab and Poe, 2012)
Component Chemical Formula Volumetric composition (%)
Methane CH4 60.0 – 96.0
Ethane C2H6
Propane C3H8
Isobutane C4H10 0 – 20*
Pentane C5H12
Hexane C6H14
Nitrogen N2 0 - 5
Carbon dioxide CO2 0 - 8
Hydrogen sulphide H2S 0 - 5
Oxygen O2 0 - 0.2
Rare gases A, He, Ne, Xe traces
* Refers to the overall percentage of NGLs
While methane and ethane are gaseous under atmospheric conditions heavier hydrocarbons are
present in gaseous form within the reservoir but liquefy once reached the surface. This liquid fraction
is called natural gas liquids (NGLs) and, according to the amount present in the gas flow, extracted
2 Paraffin or alkanes are any of the saturated hydrocarbons having the general formula CnH2n+2
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natural gas could be called “wet” or “dry” gas. NGLs are separated from the gaseous stream and send
to refinery to be exploit as basic feedstock in the petrochemical industry or to produce LPG3. Other
commonly found gases are nitrogen, carbon dioxide, hydrogen and trace of noble gases such
as helium and argon. In addition to inert gas natural gas might contain substantial quantities
of hydrogen sulfide or other organic-sulphur compounds, which are toxic, corrosive and generated
hazardous pollutant when burned. This type of gas, known as “sour gas” has to be processed and de-
sulphurized before being transported to the final markets. Moreover, associated gas present traces of
water vapor due to the brine4 usually present at the bottom of oil reservoir. To become suitable for the
market those fractions has to be removed
1.1.2. Natural gas genesis
Nearly all natural gas extracted worldwide has a thermogenic origin: like petroleum, it is formed
following the burial and sequent thermochemical degradation of organic matter. First small aquatic
organism die and deposit at the bottom of lakes or old seas, subsequent deposition of sand buries them
below the surface where they undergo a process of diagenesis5. During burial, the mild pressure forces
water out of the deposited sediments Subsequent chemical reaction and bacteria activities decompose
the original organic polymers forming kerogen, a waxy mixture of organic compounds. As burial
depth increases so do pressure and temperature starting thermal degradation (“cracking”) of the long-
chain kerogene molecules into smaller hydrocarbons. The deeper kerogene is buried the higher is the
temperature to which it is exposed; higher temperature is associate with faster cracking reaction and
smaller molecule resulting. So, the deepest the sediment the lightest the final product.
It has to be said, however, that not all the buried organic matter forms kerogene and not all the
kerogen typologies are suited to became hydrocarbons, which strictly depends on the typology of
organic matter present and the temperature at which it is exposed.
Figure 1.1 – Oil and gas temperatures related to depth of burial
3 LPG or liquefied petroleum gas is a mixture of butane and propane 4 High salinity water found in deep reservoir (salinity > 5%) 5 Diagenesis is a process of chemical and physical change in deposited sediments during its conversion to rocks
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1.1.3. Formation of a gas reservoir
The kerogen-rich that generates the hydrocarbons is called “source” or “mother rock”; however,
oil and gas are found elsewhere, in rocks layer that lies closer to the surface, called “reservoir”. The
process that brings liquid or gaseous hydrocarbons from source rock to the reservoir is called
“hydrocarbon migration” and it is composed of two consequent steps. Primary migration, where the
hydrocarbons are expulse from source rocks, and secondary migration, when they flow towards the
surface being, eventually, trapped in the final reservoir. Hydrocarbons generation within the source
rock led to a constant increase in the internal pressure within the rock layer that, once overcome the
surrounding geostatic pressure, ejects them. After the expulsion from hydrocarbons, being lighter than
water, are pushed upward by buoyancy forces; eventually they could reach the surface originating oil
or gas seepage. For migration to take place, rocks strata surrounding the source rock have to be
permeable6 enough; the higher the permeability, the higher the quantity of hydrocarbon that could
migrate. Finally, in order to develop a reservoir (an oil/gas field), the hydrocarbons have to encounter
a so-called trap on their way to the surface. A trap requires essentially two elements: a sufficiently
porous rock to contain the hydrocarbons (reservoir rock) capped with a layer of impermeable rock
that blocks any further migration (seal rock).
Figure 1.2 – Formation of an oil and gas reservoir
6 In earth science, permeability indicate the ability for fluids (gas or liquid) to flow through rocks: it depends by the rock
typology (pores dimension and connection) and pressure (high compression state will lower the permeability). It is also distinguished between primary, which depends only on rock lithology, and secondary, which considers fractures and faults formed resulting from tectonic deformation.
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1.2. Natural gas final uses
Natural gas is probably the most versatile between all the primary energy feedstock and it
extensively employed in all the final energy uses. It is employed as fuel source for its combustion
characteristics or as basic feedstock in other to produce a wide variety of other chemical component.
1.2.1. Residential and commercial uses
The uses of natural in those two sectors consist mainly in space or water heating or cooking, where
natural gas represents the best choice in terms of both ease of use and cost effectiveness. Cooking
with natural gas allows an easy temperature control, self-ignition and self-cleaning of the range.
Regarding water and space heating, gas-fired condensing boiler allows the recovery of its heat of
vaporization achieving the highest possible efficiency. Methane is a colorless, odorless gas and,
despite not being toxic, it is particularly dangerous due its ignition-ease. For this reason, a small
quantity of an odorant is always added to ensure the rapid detection of any leakage that may occur
during use.
1.2.2. Industrial uses
Natural gas is widely employed in industrial process as fuel for industrial furnaces or co-generating
systems, as basic chemical feedstock or as a cooling media for large refrigeration plant. Natural gas,
together with electricity, is essential in all the energy-intensive industries such as iron metallurgy,
cement works and paper mills where it could make up for nearly half of the production costs. Industrial
cogeneration is a cost-effective solution when the process requires both heat and electricity. Methane
and NGLs are the basic feedstock for a wide variety of components in the petrochemical or
pharmaceutical industry. The reaction between methane (CH4) and molecular nitrogen (N2) is the first
source of ammonia (NH3), which is the base-block of all fertilizer employed worldwide. Beside its
direct uses it could also be converted in “syngas” (synthesis gas, a mixture of hydrogen and carbon
oxide), and further process to obtain methanol or pure hydrogen. Recent improvements in refrigeration
technologies made natural gas the best available solution for large refrigeration system based on a
gas-absorption cooling cycle. This system exploits the heat generated by natural gas combustion as a
thermochemical “compressor” to operate the refrigeration cycle: gas absorption cycle do not require
any electricity and have no moving therefore being much simpler and having limited maintenance
costs.
1.2.3. Power generation
The technological development on high-temperature resisting material and cooling system on
aircraft gas turbine create a sharp cost reduction, which allowed the employment of this technology
in power generation system. CCGT (combined- cycle gas turbine) combine two different
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thermodynamic cycles: a gas-fired Joule-Bryton and a traditional steam-based Rankine cycle.
Residual heat contained in the high-temperature flue gas discharge by the gas turbine is employed to
produce the superheated vapor sent to the steam turbine. The combination of two different cycles and
the use of gas turbine “waste heat” allows greater efficiency that single cycle power plant. The highest
efficiency ever achieved in CCGT surpassed 60% in comparison with the 40% of the traditional coal-
or oil-fired plants. Compared with traditional plants CCGT tends to have higher operational cost (fuel
costs) but lower initial capital investment. CCGT are easier and faster to build and, given the same
electricity output the total land requirement is smaller. Moreover, gas turbine could be turned on and
off very quickly and the output load could be variated with the same rapidity, making them perfectly
suited as backup generation for the unpredictable and variable renewable generators.
Figure 1.3 - Scheme of a CCGT power plant
1.1.4. Transportation
The high-energy content and high octane number of methane makes it suitable to be employed in
an internal combustion engine. No particularly design injector or mixer is required since optimal
mixing and ignition ease are intrinsically ensured by its gaseous nature. Problems associated with
carrying a gaseous fuel on a vehicle (storage tanks dimension and weight) limited its development as
a fuel for transport. Recent improvement in storage tank design and stricter emission limit regulations
are incentivizing automakers to design gas-powered model. Natural gas energy density per unit
volume is much lower than gasoline. Natural gas cannot be stored at ambient condition ant is either
pressurized (compressed natural gas or CNG), or liquefied (liquefied natural gas or LNG). Storing a
liquid at such a low temperature requires special cryogenic tanks that are too expensive to be installed
on an average passenger car. LNG is, in fact, reserved to heavy-duty vehicles (alone or in a dual-fuel
combination with diesel) while passenger car or public transportation buses employs CNG systems.
Regardless of the type of storage, it reaches the combustion chamber in gaseous form pre-mixed with
air to assure the best engine performances. Natural gas could also be converted into liquid synthetic
23
fuel solving the problems relate to the storage of a high-pressure gas or a cryogenic liquid. Gas to
liquids (GTL) is a refinery process that converts natural gas or other gaseous hydrocarbons into longer-
chain hydrocarbons such as gasoline or diesel fuel.
1.3. Natural gas environmental benefits
“Global warming” and “climate change” describe the rise in the average temperature of Earth and,
despite skepticism; it is become a widely accepted fact supported by a wide numbers of scientific
research and observations. It is undeniable that human activities are emitting in the atmosphere a wide
range of gaseous substance that contribute to increase the greenhouse effect7. This is the reason why
the increasing level of carbon dioxide (CO2) in the atmosphere generates so many worries; carbon
dioxide is an odorless and colorless that is neither toxic nor dangerous to human but it is the most
common GHG. Carbon dioxide is the product of all combustion reaction8 and the massive reliance on
fossil fuel contributes significantly to its production: since the industrial revolution the level of
atmospheric CO2 have been steadily rising.
In order to decelerate this emission trend 175 countries, which are responsible for more than half
of the total GHG, subscribed the Kyoto Protocol (1997) pledging to reduce their total GHG emission
under 1990 level within 2020. In order to achieve this ambitious goal different measure should be
adopted: from a serious improvement in energy efficiency in all energy end-uses sector to the increase
of renewable energy generation. Renewable energies, although, still have to face a substantial
improvement in their technology and scale-economy before being able to replace completely fossil
fuel.
Cost-effectiveness and the emission cut made with energy efficiency measure tends to be very
high at the beginning, when applied to a generally inefficient situation (such as power generation
sector in developing countries) increasing their cost and reducing the obtainable results as the overall
efficiency level increase. In Europe, where since the energy crises of the seventies energy efficiency
has always been a priority, further energy efficiency measure tends to be always less cost-effective.
The best results, in terms of emission cut, would be a fuel switch in the power generation sector
employing natural gas instead of the more polluting coal or oil. Methane, in fact, being the simplest
of all the fossil fuel, has the “greenest” combustion and emits almost half CO2 compared to coal and
nearly 30% less when compared to oil and oil product. (See table 1.2)
The low emission combustion of natural gas is enhanced in the power generation sector.
Because of their high efficiency CCGT have the lowest total emission (considering both direct and
indirect emission) between all thermal power plants. (See figure 1.4)
7 Greenhouse effect is the process with whom part of the thermal radiation emitted from a planetary surface is absorbed by the atmospheric layers and re-radiated back maintaining the temperature within atmospheric layers 8 The unique exception is hydrogen (H2) being the only fuel without any carbon atoms its combustion reaction do not generates any carbon dioxide
24
Another problem of great importance regards air pollution and related illness; as for global
warming a substitution of traditional fuels with methane would reduce in a lower pollutant level.
Natural gas combustion does not produced any sulphur dioxide or particular matter and has the lowest
emission of carbon dioxide and nitrogen oxide. (See table 1.3)
Table 2.2 – Specific energy, energy density and yielded CO2 for different fossil fuels
Fuel Specific Energy
(MJ/Kg)
Energy Density
(MJ/litre) Chemical Formula
CO2 emission
(g CO2/MJ)
Propane 50.3 25.6* C3H8 59.9
LPG 46.1 27 C3H8 + C4H10 59.8
Ethanol 21.6 - 23.4 18.4 - 21.2 CH3 CH2OH 67.2
Gasoline 45.8 32 - 34.8 C7H16 74.1
Diesel 48.1 36 - 40.3 C12H26 70.7
Biodiesel 37.8 33.3 - 35.7 C18H32O2 ~ 75
Methane 55.5 23* - 23.3* CH4 50 Natural gas 38 - 50 17.7* - 23.2* mainly CH4 50 - 60
Crude Oil 41.9 28 - 31.4 C14H30 96.8
Wood 16 - 21 2.6 - 21.8 (C6H10O5)n 94.2
Coal 29.3 - 33.5 39.8 - 74.4 - 99.2 - 109.8
Hydrogen 120 - 141.9 8.5* - 10.1* H2 0
*liquefied
Figure 1.4 – Equivalent carbon dioxide emission for different electricity generation (NEA, 2009)
Table 1.3 – Air pollutant emissions from fossil fuels steady combustion (Mokhatab and Poe, 2012)
Fuel SOX NOX CO2 PM
Coal (3% Sulphur) 1.935 0.430 85.3 2.532
Coal (1% Sulphur) 0.645 0.430 85.3 2.293
Fuel Oil (residual) 1.433 0.406 74.8 0.096
Fuel Oil (distillate) 0.143 0.215 74.2 0.048
Natural Gas - 0.287 49.4 -
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1.4. Natural gas global consumption
Natural gas development as a worldwide energy sources is very recent: at the beginning of the
fifties natural gas was covering less than 1% of world primary energy consumption, compared to the
25% of 2013. This consumption increase has been a worldwide phenomenon but, as fig. 1.3 clearly
shows, the extent of this increase varied greatly in different world region.
Figure 1.5 – Historical gas consumption per region (elaboration on EIA database)
Reliance on natural gas increased in all world region but, while the increase of the United States
and Europe have been relatively modest, Middle-Eastern and Asiatic countries experienced a dramatic
surge in their consumption. The reasons of this increase in consumption is country-specific: in Asia
is related to the economic and population growth of China and India while in the Middle East is related
to the substitution of oil with gas for electricity production.
According to all analyst estimation made (Bp, Eia, Iea) natural gas consumption will be the fastest
growing energy source in the next future. Some of the driving forces behind this increase consumption
are easy to forecast, as the Chinese and Indian population growth, while some are more complex and
depends on government decision and environmental policies. In the next year, new power plants
would be required to cover the increasing electric demand of developing countries and to substitute
nuclear power station that are going to be shut down following Fukushima disaster. The most
economical solution to replace nuclear power plant would be with coal-fired power plants. However,
stricter regulation on maximum pollutant emission combined with an increase in the price of CO2
could make CCGT competitive or even convenient with respect to coal-fired ones. Moreover, the
increasing share of non-predictive and erratic renewable electricity generation, such as wind farms
and solar fields, needs a proportional increase in backup generators able to variate their load very fast
to compensate production outrages. At the state of the art, the best-suited technologies are CCGT.
26
While the biggest absolute increase in gas consumption will come from residential and power
generation the highest percentage growth would be seen the transport sector. Nowadays, road
transportation is dominated by oil products but technological improvement on gas-based engines and
storage tanks would make natural gas powered cars ever more reliable and convenient. As previously
stated the entity of these consumption increase rely on the future governments policies; nevertheless
all those trends are yet visible showing the dawn of what the Energy International Agency defined the
“Golden Age of Gas”.
Figure 1.6 – Forecast on natural gas consumption per world region – billion cubic feet /year (BP Energy Outlook)
1.5. Natural gas global reserves
For most of the century, natural gas was considered an “economic viable byproducts” in the oil
extraction process; therefore oil&gas companies were mainly focus on the exploration and
exploitation of oil reserves. Increased interest in the development of natural gas projects led to a
dramatic increase in the quantity of proven reserve: 2013 estimation were of 185.7 trillion cubic, 57%
higher with respect at 1993 level and 32% with respect to 2003. More than two-third of the world
reserves are located in just two world region: Eurasia9 (or FSU, Former Soviet Union) and Middle
East. Quantity of gas reserves on itself is somehow difficult to interpret when not compared to the
9 According to British Petroleum world subdivision Eurasia accounts for Russia and other central Asian countries once part of the Soviet Union.
27
level of production. The reserves/production ratio, gives an idea of how many years current field could
be exploited without any technological improvement or any other new discover.
This ratio is sometimes confused with “remaining lifetime” of the resource, which is, of course,
wrong. Reserves indicated the quantity of resource known that could be recover with current
technological level under current market condition. It is, thus, evident that any technological
improvement, increase in final price or new discovery will led to an increase in the gas reserves.
Figure 1.7 – Natural gas proven reserves by region – (BP Statistical review of world energy)
Despite the environmental superiority with respect to all other fossil fuels increase reliance on
natural gas is criticize for its intrinsic non-renewable nature. Some environmentalist claim that natural
gas will not solve any of the environmental problems but just delay them while subtracting funds to
renewable energy. One of their main point of the critics is that natural gas, as oil and coal, is an
exhaustive energy sources and, once depleted, will leave our society without any other alternative
energy source: investment in natural gas project, therefore, should be avoided in favor of renewable
energies. Oil and gas depletion is a widely discussed topic, especially by general media, which,
sometimes, are not very accurate in their scientific explanation and could generate baseless worries.
For example, reporting that the lifespan of gas reserves estimate in 2013 was sixty years could be
misleading; the “lifespan” (better “remaining lifetime at current rate of production”) does not indicate
the amount of time before the total depletion of oil or natural gas. This “end of oil and gas” fear is
largely unfounded and it is based on a misunderstanding of the term “reserves” that is often taken as
“total quantity of oil and gas present on earth”. “Remaining lifetime” indicates simply the ratio
between what has been discovered and considered profitable for extraction and the extraction rate.
For example, according to British Petroleum historical data series, the R/P ratio was of 54 years in
1983 and is 55 years today.
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29
Chapter 2
Natural gas industry and market
Natural gas is the most versatile and “greenest” of all fossil fuels: it has a high heating value, it
could be employed in almost all energy end-use sectors and has a smaller environmental impact
compared to other fossils. Despite all of its advantages, a single aspect prevented it from becoming
the first energy source employed worldwide: its gaseous state. Technologies required to transport and
store a gaseous fuel are more challenging, and thus costly, than a solid (coal) or liquid one (oil).
Natural gas is exploited as close as possible to the production facilities; the first natural gas
markets were created because of the presence of associated fields (i.e. presence of both oil and gas)
relatively close to consumption centers. High transportation costs limits cross-border exchanges;
nowadays only one third of the gas produced exits the producing country border to be exported
elsewhere, a very low percentage compared with the almost 70% of oil. Moreover, most of the natural
gas exported is produced by a bunch of countries (roughly the first 10 exporters covers nearly 80% of
the overall sales on the global market), mainly Russia and the Middle East, which have an incredibly
high share of the markets and are the much more influential than oil producers.
The regional separation between markets have been lowered in the last decade by the increased
number of LNG trading but the total volume exchange are still not sufficient to modify the intrinsic
characteristics of the gas market.
2.1. Overview of the natural gas supply chain
The production, transportation and distribution of natural gas is a complex process that involves a
high number of actors, from oil majors to final residential customers; any every step of the supply
chain is defined according to its “position” in the oil & gas industry production stream.
Generally, the subdivision of the gas supply chain is the same of as the oil one, since they are often
associated and some steps (especially production) are very similar.
Upstream (Production & Processing): all facilities and activities required to produce oil and gas;
well drilling, well completion and production
Midstream (NG Transmission & Storage): gas treatment operation and its transportation to the
end market (both via pipeline or shipped) and its storage
Downstream (Distribution): distribution and marketing of natural gas
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Figure 2.1 – Natural gas supply chain
2.1.1. Upstream
Upstream refers to the development of a natural gas (or oil) project and comes after exploratory
phase where, trough geological survey and seismic analysis, natural gas deposits are identified.
Determining whether to drill a well depends on a variety of factors, mostly the economic potential of
the hoped-for natural gas reservoir. If the first exploratory well strikes a natural gas deposit a series
of tests are carried in order to determine the size and production capacity of the reservoir, once this
consideration are is known, the final decision, whether to start production in the field or not, is taken
and subsequent development is optimized. Main distinction in the upstream process is not between oil
and gas wells, which have only minor differences but rather between on- and offshore facilities.
Onshore facilities employ standard technologies with only minor differences between them offshore
facilities have a wide range of technical solutions based on geographical location and water depth.
2.1.2. Midstream
Midstream section comprises all the process and facilities that are required in the after-production
phase; gas gathering, treatments and transported to the final markets. The first step is the “gathering”;
offshore facilities also includes a gathering system and a processing plant on board, onshore facilities
gathers all the raw gas coming from the wells in the same area and process it in just one plant. Well
gas, or “raw natural gas”, is purified through a pollutant removal process and then separated into its
marketable fractions (methane and NGLs).
31
Gas treatment includes all units and processes required to separate methane from unwanted
components such as acid gases (CO2 and H2S), water vapor and inert. Another process done in the
processing plant is the so-called calibration: that is the mixing of natural gas with other gases to match
a specifically required calorific value. Since the required calorific value is normally lower than the
one of pure methane, the stream could be diluted by adding an inert.
Once the gas has been processed, it is transported to the final market; by either compressing it and
sending it through a pipeline system or shipping it, after the liquefaction process, with specifically
designed cargoes. In order to be sent via pipeline, natural gas has to be pressurized: since internal
friction will diminish the gas pressure additional compressor stations might be required in case of long
distance transportation. Pressurization is performed with centrifugal compressors driven by a turbine,
fueled with part of the incoming gas, or by an electric engine. Once natural gas reaches the distribution
network it is distributed into smaller and shorter pipe to the final consumers.
LNG shipping requires a liquefaction process: unlike other gasses natural gas cannot be liquefied
by simply increasing its pressure but it has to be cooled until it reaches its ambient pressure dew point
(- 162 °C). Natural gas liquefaction processes are covered by a patent and, in general, are generally
based on a multi-stage cooling process: pre-cooling (until -30 to -50 °C), liquefaction (from – 30 to –
125 °C) and sub-cooling (to the final temperature of -162 °C), those three section are normally
separated and employ different coolants. Once liquefied, natural gas is loaded in the cryogenic tankers
of an LNG-cargo; even if the insulation is designed to minimize heat losses a part of the cargo will
still heat up and boil off. To prevent excessive loss of the cargo LNG is stored as “boiling cryogen”;
so as the vapor boils off, the heat of vaporization is absorbed from the rest of liquid cooling it down
with an effect called auto-refrigeration.
Figure 2.2 – Natural gas midstream facilities (ABB – Oil and gas production handbook)
The receiving terminal is called regasification facility: LNG is stored in local cryogenic tanks and,
when required, is regasified to ambient temperature, pressurized and sent to the pipeline network.
Compared to the complexity required for a liquefaction plant the receiving terminal is rather easy;
rigasifier is normally a simple LNG-seawater heat exchanger.
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2.2. Gas transportation
The transportation choice thus depends on the distance to cover but, mostly, on the possibility of
building a very long pipeline to export gas. Beside the increasing capital and operation costs required
for longer pipelines some other geopolitical problem might be involved. Long trans-national pipelines
often have to cross other countries and pipeline owner should pay what called “gas transit fee”.
Moreover, the presence of such sensible infrastructures might pose some security risks or generate
tension between the two countries involved (as for example the Russia-Ukraine gas crisis).
LNG cargoes, on the contrary, do not involved static infrastructure and are much flexible: the same
liquefaction facilities could supply more receiving facilities located in different countries. Therefore,
the choice between LNG and pipeline gas depends on a variety of factors, geographical position,
geopolitical situation and market-related evaluations.
It is clear, although, that, whatever the chosen solution, technological complexity and related costs
are much higher with respect to oil. In case of a pipeline, gas transportation requires higher quality
materials and welding in order to withstand pressure and compressing a gas to make it flow through
a pipeline is more costly with respect to a liquid. When comparing LNG and oil shipping the difference
is even greater: while LNG requires a complex cryogenic process while oil needs just to be loaded
and offloaded. In the end, transportation costs represent a fraction between 40% and 70% of the
marketable price, much higher than the 10% of oil. This cost gap explains rather easily, what has
always been (and still is) the limit of the diffusion of natural gas.
2.3. Natural gas market structure
Even if technological progress decreased costs in all the supply chain (especially in the LNG
industry) natural gas remains a regional energy source. In 2014, natural gas global production reached
3’460 billion cubic meters, of this, only a third crossed national border to be exported; a percentage
that is nearly half the one of oil. The global gas market is heavily polarized with the 10 biggest
importers and exporters covering almost 80% of the overall natural gas trade worldwide. As figure
2.3 clearly shows, there exists a polarization also in the export typology: piped gas trading happens
in Europe and North America while LNG cargoes are directed mostly to the south Asian markets. This
heavy regionality gave birth to a different number of gas markets clearly distinguishable for their
geographical location and their pricing system. The world’s biggest, both in terms of consumption
and imports, are North American, the European markets and the south Asian markets. Those three
markets differ primarily in terms of geographic location, availability of natural resources, country
energy mix and reliance on natural gas.
33
Figure 2.3 – Major gas trade flow worldwide in 2014 (billion cubic meter) - BP Review 2015
All these factors generated wide differences in the market structure in terms and contract
typologies as the different prices shows. In fact, while oil has a global price set for specific
benchmarks10 natural gas has a separate market with separate prices and a very small amount of
interaction between them.
Figure 2.4 – Gas price in major distinct market - BP Review 2015
10 A benchmark crude or marker crude is a crude oil that serves as a reference price for buyers and sellers of crude oil.
There are three primary benchmarks: West Texas Intermediate (WTI, US), Brent Blend (extracted in the North Sea, the European benchmark), and Dubai Crude (Persian Gulf benchmark).
34
2.3.1. Gas market characteristics
Like other economic goods, the structure of each regional gas market depends mainly on their
dimensions, number of suppliers and consumers, and the availability of alternative energy sources as
substitutional goods. Market structure is also influenced by gas infrastructures present within the
market border (i.e. extent of pipeline network, transport capacity and storage) and its accessibility to
all market participants. Figure 2.6 summarizes those concepts showing the four typology of existing
gas markets presented in order of increasing liberalization and competitiveness: from the regulated
markets typically of countries with nationalized oil and gas industry to the open and well-integrated
“gas on gas market”.
Figure 2.5 – Major gas market characteristics
There are countries where the energy markets are fully liberalized (as the United States) or have
an ongoing liberalization process (the case of the Europe) and others where oil&gas resources are
nationalized and the energy markets are operated by state-owned companies. In these countries,
especially the Middle-East countries and Russia all the natural gas supply chain steps are covered by
a unique vertical-integrated11 company whose directors and executive are nominated by the
government (as is the case of Gazprom in Russia); and prices are often fixed. This type of regulated
markets are associated with a rigid political structure and State control in all the aspects of a country’s
economy; the main examples are Russia, the Middle East countries and China.
11 Vertical integration is an arrangement in which a company owns and directly controls all the supply chain of the market specific product or service it sells
35
At the opposite end, there is the so-called “gas to gas” market typical of North America (Canada
and the US) and, to a lesser extent, of the United Kingdom. Main characteristic is the high number of
players (on both the demand and supply side), the presence of a large and well-integrated gas network
able to reach every customer and the presence of ample storage systems. All the gas-related
infrastructures (pipelines, storage systems and in some case LNG receiving terminals) are open and
accessible to all market participants, with so-called “third-party access12” thus increasing
competitiveness and market efficiency. Market price is determined by the interception of demand and
supply referred, normally, to regional benchmarks, such as the regional main stock market.
The second group, which includes Continental Europe and some Asia-Pacific countries (Japan,
Taiwan and South Korea) present a reduced market dimension, especially on the supply side, and rely
heavily on foreign imports. The main differences between European and the Asiatic market are: the
typology of imported gas (via pipeline for Europe and via LNG for Asiatic countries) and connection
of the market; Europe could be considered a unique market while Japan, South Korea and Taiwan are
completely separate.
European gas market has intrinsic different characteristics related to its historical evolution: the
actual network is the unification of different gas networks specifically designed to meet country
internal demand. For this reason, the European network is still scattered and not well integrated. Gas
is imported with long-term contracts (15 to 30 years) based on an oil-indexing. Final gas price is the
result of a formula that includes volume of natural gas contracted and average prices of oil and oil-
based fuel.
Even if the contract formulations are essentially the same, prices vary along the continent in
relation to the volume contracted and the market power of the exporting country. The insufficient
connection in the union contributes in creating areas where just one supplier (Russian Gazprom)
covers all country’s gas demand; this monopolist condition is translated into a high variability in final
prices that depends, mostly, on political relationships. One of the main goals of the European Union,
since its formation, has been the creation of a unique European energy market for both electricity and
natural gas. Despite the oligopolistic situation, some steps into the deregulation process has been taken
and there are some gas hubs with a still limited, but growing, futures market.
12 Third Party Access (TPA) is a regime that obliges companies that own or operate transmission and distribution networks (gas and electricity) for offering a non-discriminatory service to the third parties to the extent that there is capacity available. TPA impose the obligation to the network owner/operators to offer capacity if there is available capacity, or if it has not been allocated before. Enforcing TPA in the use of pipelines transmission network is a policy trend observed in all countries that aim to liberalized and increase competitiveness in energy markets
36
2.4. The European model: the US gas market
The US natural gas market is the biggest and most competitive gas market worldwide. Market
mechanisms in the newborn European hub are similar, but not as well developed or complex, even if
the legislative path takes this as a reference point. The main difference between the United States and
the European market is the extension of liberalization and deregulation, the dimension of the supply
side and the important role of gas marketers. Natural gas marketers have a quite complex role, which
does not fit exactly into a particular step in the natural gas supply chain. In general, gas marketing
could be described as the sum of all the processes required in order to coordinate the business of
bringing natural gas from the wellhead to end-users. Before the liberalization process, there was no
role for natural gas marketers; producers sold natural gas to pipelines transmission companies who
then sold to local distribution companies who, finally, sold it to the end user. This market structure
was rigid and separate in blocks; infrastructure ownership and price regulation at all levels of the
supply chain left no place for other market participants.
Liberalization process started in 1978 with the “Gas Policy” establishing the end of state authority
regulation over the wellhead price13. The whole required nearly 25 years and three other fundamental
steps to result in a fully competitive market. Firstly, the possibility to each end consumer to purchase
gas directly from the producer was enforced, secondly, The TPA was made mandatory on every
pipeline of the network (FERC14 order no.436, 1985) and, finally, transport and marketing activities
were separated (FERC order no.636 in 1992). The creation of financial markets gave marketers the
possibility and the instruments to hedge (i.e. reduce) the intrinsic risks related to price volatility. In
the end, it is the predominant role of marketers that ensures the efficiency15, transparency and
liquidity16 of the American market; the resulting market is fully open to concurrence with a clear
pricing scheme and without actors with high market power able to influence the final price.
13 Price of natural gas at the moment of extraction; represents the pure cost of extraction and processing, or the final cost excluding other expenses required to transport and deliver natural gas. 14 Federal Energy Regulatory Commission is the United States federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing and oil pipeline rates. 15 Market efficiency refers to the capacity of market players to optimize the allocation of a commodity thus managing the potential and rapid variation, called “swings”, of demand or supply. 16 Market liquidity is a complex concept since it incorporates four distinct characteristics: depth, breadth, immediacy, and resilience. Breadth and depth refer to the market dimension or quantity of different bids and offer present on the market and to the price variation that follows the trading of large volume of the given commodities. Immediacy is the ability to trade large volume in a short period of time, and resilience to the capacity to recover, in a short period of time, the market natural supply/demand equilibrium after a shock
37
2.4.1. Physical and financial market
Natural gas market in the USA is essentially a commodity market like corn, metals, or oil ones.
To be considered a commodity, a product must have the same characteristics independently of its
geographical location and natural gas, once processed, fits the description. The price of each
commodity is determined by the interaction between supplier (producer or importers) and consumer;
a variation in one of the two market forces will cause a variation in the resulting price.
Natural gas trading, as other commodities, involves both physical volumes and financial contracts
and has two distinct markets according to the time step of the purchased goods: the spot market and
the futures market. The Spot market is the daily market, where natural gas is bought and sold “right
now” while futures are contract referred to a future purchased (normally from one month up to 36
months in advance). Natural gas futures are traded with a number of complex derivatives contracts
that are essentially employed to reduce market associate risks or to speculate on future trends of gas
price.
Physical trading occurs in locations called “market hubs”, physical markets located at the
intersection of major pipelines or in proximity to major consumption centers. There are over 30 major
market hubs in the U.S., the principal of which is the Henry Hub, in Erath, Louisiana. Its importance
is due to its strategic positon: it interconnects nine interstate and four intrastate pipelines and it is the
access route of all the natural gas produced in the Gulf of Mexico. Being the most important hub its
price trend is the reference for the rest of the country and the basis for future contracts and speculation.
Prices in the other hubs could be seen as the Henry Hub price and a quantity called “location
differential”, which accounts for transportation costs.
Physical trading contracts are negotiated between buyers and sellers and includes a series of
standard specification: volume, gas quality specifications, receipt and delivery point, contract length
and other terms or legal conditions. There are essentially three typology of trading contract: swing
contracts, baseload contracts, and firm contract; swing and baseload are typical of liquid and
competitive markets while firm contract, being more rigid, resembles the typology existing in Europe.
Swing or baseload contracts are characterized by the absence of a delivery obligation: none of the
parties involved is obligated to deliver or receive the exact volume specified. Firm contract introduces
this legal obligation introducing legal recourse in case of failing to meet obligation agreements;
involving a certain rigidity in the purchased volume, delivering time and natural gas pricing thus being
the closest typology to the one existing in Europe.
Efficiency and effectiveness of both physical and financial markets are needed to ensure that the
natural gas price reflects its supply and demand and it is not distorted by the predominant position of
one of the market actors. Not surprisingly, the most efficient and liberalized market evolved in North
America (Canada and the US are considered as a unique gas market). Vast internal gas resources, the
high amount of oil&gas companies operating in the upstream section combined with big industrial or
consumer, enhance the efficiency in all the natural gas supply chain guaranteeing lower price and
higher benefits for final consumers.
38
39
Chapter 3
The European gas market
The European17 energy market has historically been the second largest worldwide after the North
American ones. Even if its role in terms of production is nowadays very limited (301.68 billion cubic
meter 10% of world production in 2013) nearly half of the global exported gas in imported within the
Eu. Since the end of the Second World War, one of the goals of European state was to create a common
and open market with no customs barriers, both for common goods and energy related-commodities.
The first step made towards the creation of a unique and liberalized energy market (electricity and
natural gas) has been directive 98/30/CE, which enforced a series of standards in order to modify gas
market structure basing it on the U.S. liberalized model. The evolution of European gas market toward
a fully liberalized market follows the steps of North America’s deregulation but there are several
differences between the United States and the European Union, which complicate, c the deregulation
process.
The main problem, when comparing Europe to the United States, is that the different member
countries have different market structures that depend on their history, economic evolution and
availability of energy sources. The evolution of the North American gas market benefited from the
numerous gas fields spread across the country and the presence of heavy industries or big metropolitan
areas nearby. First, pipelines linked productive fields with consumption centers nearby, and, once the
consumption of natural gas was established in all the country, the long transmission pipelines were
built; nowadays almost all the U.S. territory is covered and gas could be moved virtually everywhere
in the country. European gas networks, on the other hand, cannot be considered unique and integrated.
Another major problem is the high dependency from foreign exports; two of the three major importers
(i.e. Russia and Algeria) are extra-EU countries with a rigid political system and a monopolistic
management of their hydrocarbon resources.
In the near future Europe has to strengthen its internal networks improving connection between
member countries, build new import facilities and diversify supply routes, and, wherever possible,
increase its internal production. Only under these conditions, the European gas market could have the
possibility to evolve becoming a truly integrated and competitive market similar to the North
American model.
17 As mentioned in the introduction, the adjective “European” refers to the European Union and not to the geographical definition of Europe. For example, Norway is in Europe (the continent) but not in the EU and in this chapter, it would be referred as part of the extra-EU imports.
40
3.1. European energy consumption
To show the importance of natural gas in the European energy mix and its future prospects, it is
necessary to give a quick description of the overall energy consumption of the union. Three main
“parameters” are required to give an extensive overview of a country’s energy-mix: primary energy
consumption, final energy consumption and power generation fuel-mix.
Primary energy consumption refers to the direct use of the raw energy source, without any other
transformation. It includes direct employment in final uses, such as natural gas for space heating or
cooking; or a conversion into a secondary energy source (or energy carriers) such as refined oil
products or electricity produced in power station. Primary energy sources are fossil fuels (crude oil,
coal, and natural gas), mineral fuels (natural uranium) or renewable sources (solar energy, wind,
hydro, and biomass).
Final energy consumption describes the employment of the energy carrier, either primary
(natural gas) or secondary (oil refined products, electricity) to generate useful effects such as lighting,
process heat or motion forces.
Power generation energy-mix describes the typology of power stations a country employs to
produce its own electricity.
Figure 3.1 – Energy balance
Together these three indicators give an exhaustive description of the country’s energy mix, which
reflects the structure of its economy, its historical evolution and the availability of energy sources.
Despite their similarity, all the member countries of the European Union exhibit a different and unique
energy-mix.
41
The differences existing in the countries energy mix are even wider when specifically describing
the role of natural gas into this mix: consumption level, end uses and extent of the dependency on
foreign imports. Because of the geographic, historical and economic differences, existing between all
the members states the energy-mix would be described separately by country or country groups rather
than for the entire union. Chosen countries and country groups are the following: France, Germany,
Italy, the Netherlands, Spain and Portugal, United Kingdom and Ireland, Eastern Europe, while the
remaining member state are grouped together in other EU countries.
Germany, France and Italy are the three biggest economies of the continental European Union.
Germany has the highest energy consumption in Europe, which is associated with its high industrial
production, and shows an equilibrated energy mix (referred to primary energy). France and Italy on
the contrary present a slightly unbalanced one: France towards nuclear energy and Italy, despite being
a net importer, towards gas. Netherlands is the biggest gas producer and exporter of the union; not
surprisingly, its energy mix show a high percentage of natural gas. Spain and Portugal are net gas
importers, and, until the first connections with Algeria were built in 1996, all the gas consumed was
imported through LNG shipping. United Kingdom is the European largest oil producer and second for
natural gas; its gas network has remained completely separate from the continent until 1998, when the
first submarine connection with Netherlands (the Balgzand-Bacton interconnector) was built. Due to
the availability of numerous gas fields spread over the country and because of the high production of
the North Sea, the UK has historically been almost self-sufficient, thus being able to deregulate its gas
market reaching a structure similar to the North American one. During the last decade, however, the
increase in internal gas demand combined with the declining production of North Sea fields
transformed the UK in net importing countries. The last group is the “Eastern Europe bloc” that
consists of the three Baltic republics (Estonia, Latvia and Lithuania) and the eastern European
countries (Poland, the Czech Republic, Slovakia, Hungary, Romania and Bulgaria). These entire
country share a similar energy-mix characterized, with the single exception of Romania, by a high
coal consumption and a still low penetration of natural gas in the energy-mix. Having been satellite
states of the Soviet Union they all heavily rely on Russian gas imports and present an underdeveloped
gas network with few (when none) connections with other European countries.
Figure 3.2 represents the primary energy consumption for the selected countries clearly showing
the penetration of a single energy source within the country’s energy-mix and the total level of overall
energy consumption.
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Figure 3.2 – European primary energy consumption (MToe) for 2013 (elaboration on Eurogas statics)
While primary energy accounts for all the energy transformation occurring within a country’s
border, final energy describes the utilization in end-processes that produce useful outputs for human
activity. Each energy source is used for different goals (such as ambient heating for natural gas,
electricity for lighting, oil-products for transportation) that are normally grouped based on the end use
sector. Fuel consumption for power generation, being an energy transformation from primary source
(fuel) to secondary source (electricity), is not included. The four main final energy end use in Europe
are transport (31.8%), households (26.2%), industry (25.6%) and services (13.5%). Building-related
energy consumption is the highest and energy source employed are mainly natural gas (space heating
and cooking) and electricity to run the HVAC18 system.
Figure 3.3 shows the final energy consumption breakdown for countries, unit is still millions of
tons of oil equivalent but as mentioned above, products considered there are different. Not
surprisingly, oil products are the most employed energy carriers in all the countries considered;
transportation consumption absorb more than a third of the all-final energy consumption and in this
sector practically no alternatives to oil refined products exists. Natural gas, due to its high versatility,
occupies the second position in all countries with the only exception of France, where, as previously
mentioned, electricity generated by the uninterruptible nuclear plants is exploited even in end uses
were, traditionally, gas is employed. The lowest consumption is in the Iberian Peninsula where the
mild weather greatly reduces the seasonal heating requirement in comparison with Northern Europe.
Eastern Europe presents the highest consumption of solid fossil fuel (i.e. coal) in final uses; in fact,
some of the countryside areas are not connected to the gas network and space heating and cooking is
performed with oil-based fuel, or wooden biomass that in the graph is included into the “other”
column.
18 Heating Ventilating and Air Conditioning: is the set of systems required to heat, cool and control air humidity and quality within a building.
43
Figure 3.3 – European final energy consumption (MToe) for 2013 (elaboration on Eurogas statics)
The next figure (fig. 3.4) shows the breakdown of the power-generation per energy source as a
percentage of the total electricity produced within the country. This choice is due to the very different
level of total production between different countries, and, to understand the extent with which a fuel
is employed thus showing its growth possibility. The European average (Eu-28 in the graph) shows a
balanced energy-mix: coal and nuclear power are the major sources of electricity (31% and 27%
respectively), followed by natural gas (18.7%), renewables (14%) and hydroelectric power (7%) while
oil usage in power generation is marginal (2%). The single-country analysis differs from the European
average showing some important shifts towards a single energy source: nuclear in France (which
covers almost 80% of the whole electricity production) and coal in the eastern European countries.
The highest percentage of electricity production with gas-fired power plants are in the Netherlands
(53.6%) and in Italy, where, despite the dependence on extra-EU import CCGT produced 45% of the
overall electricity consumed within the country. The European electricity sector relies heavily,
especially in Germany and Eastern Europe, on coal-fired power plants. The low coal prices in the last
few years, in particular when compared to natural gas prices, has increased reliance on coal and
reduced electricity production with natural gas with predictable effects on CO2 and other pollutant
emission.
44
Figure 3.4 – European power generation (2013) (elaboration on the World Bank database)
3.2. European energy dependence
Despite being the second world biggest economy European energy consumption is rather low
accounting only for less than 15% of the world’s total primary energy consumption. Moreover, has
the lowest energy intensity19 and the lowest per-capita consumption in the OECD. The reason behind
this low-energy intensity economy lies in the high-energy efficiency, a direct consequence of the high
dependence on foreign imports. Since the energy crises of the seventies European countries invested
in order to diversify their energy mix and improve efficiency to sustain their economic growth without
being excessively exposed to sudden shocks on the global energy-commodities market.
Europe relies heavily on foreign imports: it depends, on average, 87.4% for oil and refined
products, 65.3% for natural gas and 44.2% for solid fuels on extra-EU imports. Figure 3.4 summarizes
the internal production and importation for the most important member states of the Union. This graph
resembles figure 3.2 but, when compared, the volumes are slightly higher than the previous one.
The reason behind this apparent data mismatch is that the first one was referred just to the volumes
consumed while this one indicates the sum of volume produced and imported, referring to changes in
the energy stock20 or gas injected into storage system formation.
19 Energy intensity, indicate in BTU/$, indicates the amount of primary energy required to produce a unit of gross domestic product and describes the “quality” of then energy consumption or the energy efficiency of the country described. 20 Stocks referred to amount of energy products (raw fuels) or processed ones, a part of the stock is owned by the national government and is kept for energy security reason. Stocks include crude oil or petroleum products held in storage at (or in) leases, refineries, natural gas processing plants, pipelines, tank farms and bulk storage.
45
Figure 3.5 - European energy dependency on fossil fuel (2013 data) (elaboration on Eia database)
Observing the graph some obvious considerations could be made: firstly, no country is self-
sufficient in terms of fossil fuel consumption, the only exception being the Netherlands for gas and
Poland for coal. Secondly, the highest dependence on import occurs with oil. Oil products cover more
than a third of the total primary energy consumed within the union (559 MToe, 33.36% of total) much
more then natural gas (387 MToe, 23.3% on total); The European union depends more on foreign oil
imports than natural gas ones, 87.4% for oil and refined products in comparison to the 65.3% of natural
gas.
Oil is more consumed more than gas and the reliance on extra-EU imports is higher but this
dependence is not considered a major problem, as it is the case with natural gas. In fact, oil global
market makes the reduction in the export level of a country or the disruption of importing facilities
easily manageable through the exploitation of stocks or imports from another supplier. This is not the
case with natural gas: whenever a country depends on a low number of importers or has a limited
amount of importing infrastructure a potential disruption in one of these could have dramatic results,
as happened in the winter of 2006 during the Russian-Ukraine gas dispute. A dispute between the two
national companies, Gazprom and Naftogaz, regarding the transit tariff escalated in a total interruption
of all the gas flowing through Ukraine. Many countries saw their total imports halved during one of
the coldest winters in the last decade and had to interrupt industrial consumption and shut gas-fired
power station down to keep enough gas for residential customers.
Figure 3.5 illustrates the dependence of European countries on natural gas imports; all the member
states, with the exception of the Netherlands and the UK, depends on imports for more than half of
their consumption; the situation worsens in the Baltic republic and Eastern Europe where dependence
reaches almost 100% and demand is entirely covered by imports from Russia. The excessive
dependence on a small number of suppliers is intrinsically dangerous because it exposes the country
to sudden and unexpected gas shortages.
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Figure 3.6 – European dependency on natural gas imports (2013 data) - (Eurostat map)
3.3. European gas market
In 2013, overall consumption was of 448.2 billion cubic meters (15% of global gas demand), the
total production, however, was limited to 157 billion cubic meter (5% of global production), roughly
equivalent to the 35% of the internal demand. In the last two decades growing consumption, alongside
with declining production, increased the dependence on extra-EU imports, supplied mainly by just
four countries: Russia, Norway, Algeria and Qatar. The recent instability such as the civil war in
Ukraine and or the presence of enhanced terrorist activities in North Africa and the Middle East made
gas dependence a matter of energy security.
The flexibility in final use and its environment benefits makes natural gas one of the key energy
sources to be exploited on the road to European decarbonisation in order to fulfil the commitments
of Kyoto or the ambitious goal set by the “Euro 20/20/20” 21. A necessary step to made natural gas
the desired bridge fuel is its availability and economic convenience: to reach those ambitious goals
the European gas market has to increase its dimension increasing the number of suppliers and
improving connection between member states creating a fully integrated European gas network.
21 The so-called "20-20-20" refers to the key targets set in the last “European climate and energy package” (2009).
Those targets are set for 2020 and are a 20% reduction in EU greenhouse gas emissions from 1990 levels, raising the share of renewable energy production to cover 20% of the whole demand and improve energy efficiency by 20%.
47
The following graph (figure 3.6) shows the evolution in gas consumption, production and imports
in the European Union from 1990 to 2013. Total gas demand grew steadily driven by industrial
development and the increase in gas-fired power plants. This growth continued until 2005, the year of
maximum consumption (533.2 bcm), and stayed constant until the sharp decline of 2009 in the wake
of the global financial crisis and the consequent economic shrinkage in the European Union.
This decline in consumption was caused by mainly two factors: the economic crises that reduced
overall consumption, especially in the industrial sector, and a reduction in the power generation of
gas-fired plants because of the concurrence of cheap coal and renewable energy. Natural gas
production remained stable for all the eighties (average of 225 bcm/year), saw a slight increase until
2001 when it peaked to 257 bcm before initiating a constant decline process; production level in 2013
(156 bcm/year) are the lowest in 35 years, and this decline is expected to continue.
This gap between demand and internal supply kept increasing, increasing the reliance on extra-EU
imports: the vast majority being piped gas (green bars) with only a small amount of gas imported
through LNG shipping (blue bars).
LNG imports had a major increase in the 2008-2011 period due to an increase concurrence
between LNG importer and traditional ones due to the arbitrage22 possibility that the European market
was offering in that period.
Figure 3.7 – European historical gas series (elaboration on Eia database)
22 In financial economy, arbitrage is the activity of buying shares or currency in one market and selling it in a different one profiting on the pricing differentia existing between the two markets.
48
3.3.1. European gas consumption
The major quantity of gas consumed within the European Union is in the residential and
commercial sector (199.34 bcm, 43.23% of total), second comes industrial consumption (143.2 bcm,
31% of total) and finally consumption in power generation plants (104.3 bcm, 22.62% of total).
Transportation use is marginal; 20 bcm equivalent to the 0.4% of the overall consumption, less than
the gas employed to power compressors or transportation losses.
Figure 3.8 –Eu-28 gas consumption breakdown (2013 data) – (Eurogas yearly report)
As expectable, gas breakdown referred to the separate countries varies greatly, in terms of both
total volume and percentages; based on the country’s geographical location, structure of the economy
and industrial system.
Figure 3.9 – Gas consumption breakdown for final use (2013 data) – (Eurogas yearly report)
49
Residential and commercial heating consumes the vast majority of gas in all the countries presented;
the only exceptions are Spain and Eastern Europe where the highest value is exceeded by industrial
consumption. In the Iberian Peninsula, the relatively mild weather is responsible for the low heating
requirement while in Eastern Europe (especially Poland) most of the domestic heating still uses solid
or oil-based fuel. The Industrial gas consumption gives an idea of the importance of the manufacturing
sector and the high-energy industries in the country’s economy; Germany has the highest
consumption, followed by Eastern Europe, the remaining European countries consumption are
aligned between 10 and 15 billion cubic meters a year. Gas consumption in power generation varies
greatly between the countries considered; a variation related more to the country specific energy-mix
than its actual dimension or electricity consumption. Highest gas consumption for power generation
happens in the United Kingdom (20.81 bcm) and the lowest in France (2.77 bcm) despite the fact that
France generated 60% more electric energy than the UK in 201 (533 Twh compared to 336 Twh). Gas
consumption in the transportation sector, is almost negligible, exceeding the 1% only in Italy, with
0.96 bcm equivalent to the 1.4% of the country’s total consumption.
Following graph shows the historical series of the three major final uses: residential and commercial,
industrial and power production in the 2004 – 2013 period. Gas consumed is presented in both total
volume (billion cubic meter a year, line with markers, left side axis) and as a percentage of total
consumption (columns, right side axis).
Figure 3.10 – Historical breakdown of European gas consumption (2004 - 2013) – (Eurogas yearly report)
The main gas consumption sector, residential and commercial, exhibits a discontinuous trend with
a yearly variability that depends on weather conditions and thus does not influence the overall gas
consumption decline. Industrial consumption has been growing steadily throughout the nineties drawn
by economic growth and industrial expansion; this growth slowed in the last decade, reached its peak
in 2007 and then began its steady decline.
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The Power generation sector had been the fastest growing sector; before the boom of CCGT, in
the early nineties the share of electricity produced with gas-fired plants remained substantially stable,
around 160 Twh, more or less the 6% of the overall electricity produced. Technological improvements
in gas turbine design combined with low initial capital costs of CCGT power plants and the relatively
low cost of natural gas on the market made them extremely competitive with respect to other options,
rapidly increasing their number. In sixteen years (1992 - 2008) electricity production with CCGT
increased at a yearly rate of 9% ; in 1992 total production with gas fired plants for the continent
amounted to 172 Twh (7.2% of the total) while in 2008, the peak year, production reached 738 Twh
(23.5% of the total).
The sharp decline since 2011 depends on the generalized decrease in electricity consumption
combined with high oil prices, to which the price of imported gas is linked, and the concurrence of
cheaper coal and incentive-driven renewables. Production decline has been different from country to
country according to the percentage of electricity generation covered by CCGT and the concurrence
of other sources (i.e. renewable and coal). Figure 3.10 shows the evolution of electricity production
with gas-fired power plants separated by the country chosen as benchmarks. As mentioned above
during the eighties, electricity production with gas-fired power remained steady; the “pioneering”
country was the Netherlands, due to the abundance of natural gas, Germany (East Germany at the
time), Eastern Europe, and Italy, where natural gas has been one of the energy pillars since the end of
the Second World War. The nineties saw a dramatic increase in CCGT, most of which happened in
just three countries: Italy, Spain and the UK; these three countries have also been the three countries
to experience the highest decline in production since the 2008 peak. In Italy the share of electricity
produced with CCGT declined from 162 (56% of total) to 128 Twh (45% of total), Spain from 114
Twh (38%) to 69 Twh (25%) and the UK, that experienced the highest decline, from 166 Twh (46%)
to 94 Twh (28%).
Figure 3.11 –Electricity production with gas-fired power plant (1985 - 2012) – (elaboration on Eia database)
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3.3.2. Natural gas production
In 2013, European gas production was of 156 bcm, which only covered a third (34%) of the
demand the shortfall was covered by imported gas; 56% coming from the three main importers while
the rest, around 10% is imported through LNG from nearly ten different exporting countries.
Figure 3.12 – Breakdown of EU-28 supplies (2013) – (Eurogas yearly report)
European gas production is polarized, with the two main producers (the Netherlands and the UK)
accounting for the 73% of the total, more than the sum of the production of the remaining 26 member
states. Figure 3.12 describes the cumulative production of the EU-28, from the 1980 to 2013:
production was constant to an average of 225 bcm, it increased throughout the nineties, mostly
because of the increased production in the UK off-shore fields, until its peak in 2001, 256 bcm the
56.6% of continental demand. Demand grew faster than production and the consumption/production
ratio kept increasing steadily since 1993 (production was covering 62% of the demand). In 2013
internal production reached the lowest level of all time accounting for 171 billion cubic meter, a
reduction of nearly 35% compared to the 2001 peak level (256.5 bcm).
Figure 3.13 –Natural gas production in EU-28 (1981-2013) – (elaboration on Eia database)
52
Apart from the Netherlands all other European countries experienced a severe decline in their
domestic production. Eastern European countries production declined sharply after the fall of the
Soviet Union because of the economic and political crises, other minor producing countries, such as
Italy and Germany, paid for the low investment made in exploration the completion of new wells
caused by rigid environmental regulation and long-lasting bureaucracy. However, the highest decline
was the one experienced by the UK due to the depletion of the North Sea fields. North Sea oil
production peaked in 1999 and started declining while gas production followed shortly after: the 38.8
billion cubic meters produced in 2013 were just 35% of the peak level reached in year 2000 (109.5
billion cubic meters). The only country that kept a constant production level was the Netherlands due
to the production from Groningen gas filed, the biggest gas filed in Europe. Its dimension allows it to
act as a swing producer balancing the high seasonal fluctuations of demand in northern Europe.
Recently, however, the government enforced a production cap reducing the maximum yearly
extractable base because of suspicious increased seismic activity in the area, forecasting a probable
decrease in the yearly production of the Netherlands.
3.3.3. Extra European Imports
The internal production decline led to a steady increase in the reliance of extra-EU natural gas
imports: in 1993, the amount of imported gas was 148.24 billion cubic meter (equivalent to 38.5% of
total consumption) which increased to 291 bcm (65% of consumption) in 2013. The vast majority of
natural gas supplied to the continent is imported through pipelines (250 bcm, 86% of total imports)
from just three countries: Russia, Norway and Algeria. A small amount, roughly 1% imported gas,
comes via pipeline from Libya while the remaining 14% is imported through LNG cargos from ten
different suppliers. The pricing of piped gas follows the already mentioned long-term oil-linked
contracts even if, recently. The pricing scheme of LNG’s shipping depends on the total volume sold,
contract typologies (long-term contract with constant shipments or short term) and, mostly, exporting
country willingness to adopt a more flexible contract formulation, thus varying greatly within the
continent.
Figure 3.14– Extra-EU imports in billion cubic meter for 2013 – (Eurogas yearly report)
53
Europe could be subdivided into three different “zones of influence” according to geographical
location: Northern Europe (UK, Belgium, and France) imports mainly from Norway and the
Netherlands, Eastern Europe and the Baltic republics from Russia (often, the only exporter) while the
Mediterranean area (Spain, Portugal and Italy) is supplied mostly by Algeria. Country subdivision
differs greatly from the continental average; Russia is the European main importer but its market share
varies greatly from the total of imported gas in Eastern Europe to nothing in Spain, Portugal and the
United Kingdom. Spain and Portugal rely on Algerian piped gas and LNG in similar volumes while
the UK exploits its own production and covers the remaining demand importing raw gas directly from
the Norwegian offshore gas field and, on a lesser extent, from the Netherlands. In 2013 for the first
time, Italy imported the majority of gas from Russia; the main importer used to be Algeria, until 2011
when, due to the strong contraction in gas consumption, Eni renegotiated its contract with Sonatrach
(the Algerian national oil&gas company) lowering the volume covered by the take or pay clause.
Figure 3.15 –Natural gas imports, breakdown by importer – (IEA, Natural gas information 2014)
Only eight member countries possess LNG receiving facilities (Belgium, France, Greece, Italy,
the Netherlands, Spain and the United Kingdom). Qatar, the main producer and exporter of LNG
worldwide, is the main European supplier covering nearly half of the total imports (48.5%); other big
exporters are Algeria (22.6%) and Nigeria (14.2%). The remaining LNG supplies are imported from
Trinidad and Tobago and Norway, which joined the LNG business only recently (the only Norwegian
liquefaction went online in 2009); Libya and Egypt used to be major exporter but the recent political
tension and civil war highly reduced their overall production. The two biggest importers are Spain
and the UK, while the UK built its regasification terminals at the beginning of the last decade to face
the enormous production decline, Spain has historically been the main European importer.
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The first receiving commercial facility was built in Spain in 1969 and since then, nearly all the
LNG shipped in Europe supplied Spain; in fact, until the construction of the Maghreb-Europe gas
pipeline23, LNG was the only source of Spanish natural gas.
Figure 3.16 – EU imports of LNG, breakdown by a) exporting country b) importing country
(IEA, Natural gas information 2014)
3.3.4 The European gas network
The European gas network has been established gradually during the last 70 years; initially, the
first short network was developed around the national gas fields in Southern France, Northern Italy,
Germany and Romania. The first connections were between small fields and industrial users in the
same area; the first trans-border pipeline was built to export gas from the giant gas field of Groningen,
in the Netherlands, whose operation started in 1963. A decade later, the continental production was
not sufficient to cover the increasing demand and long distance connections with Norway, Algeria
and Russia were built. The early nineties saw a sharp increase in gas consumption, which enlarged the
overall network dimensions, increased the number of import points and developed the first network
in peripheral countries such as Greece, Portugal and Ireland. The last decade saw the first connection
between England and the rest of the continent, as well as the construction of new LNG importing
facilities.
Nowadays, the European gas network is made up of more than 2000 million kilometres of
pipelines, 59 points of transboundary connections between member states, 26 points of imports from
non-EU countries, 20 regasification terminals and 15 virtual trading points24. The European network
is subdivided into four distinct regions, depending on the main source of gas, geographical distances
to new potential importers and the level of interconnection present: the Northern Region (UK,
23 This pipeline connects the Algerian gas field of Has R’Mel with Cordoba passing through Morocco and crossing the Mediterranean in the Strait of Gibraltar 24 “Virtual trading point” refer to a gas market located between the entry and exit points of the national pipeline network where gas is traded on a daily basis. Some virtual trading points (Henry Hub, Zeebrugge) are also physical hubs located at the interconnection of major pipeline; the other “virtual” covers the whole injection and withdrawal within the country.
55
Netherlands, Belgium and France), the South-Eastern Region (Italy, Spain and Portugal), the South-
Western Region (Greece, Romania, Bulgaria and, the other Eastern European countries. The non-EU
states import route is subdivided into three “corridors” listed below in order of decreasing capacity
and thus exports volume (data refers to 2013).
The Northeastern corridor from Russia (total capacity 293 bcm/year, 129.3 bcm imported)
Russia has three different supply traces to bring natural gas to the European markets. The main routes
are two: the Yamal-Europe pipeline (40 bcm/year), from the Yamal peninsula to Germany carrying
Poland and Belarus and Brotherhood and Soyuz pipelines systems (175 bcm/year), which gather
natural gas from the Siberian and Uralic fields and brings them to Central Europe (Austria and Italy)
and South Eastern Europe (Romania, Bulgaria and Hungary). The second one is by far, the largest
European import infrastructure and the majority of Russian gas flows through this pipeline crossing
Ukraine. The Gazprom-Naftogaz gas dispute showed the problem related to the excessive power of
transit countries; after this crisis, two new routes have been planned to bypass Ukraine.
The Northwestern corridor from Norway (total capacity 127 bcm/year, 106.6 bcm imported)
Natural gas imported from Norway is not yet sold with a commercial quality and has to undergo a
further refinement process: in fact, the majority of the Norwegian pipeline system conveys raw gas
directly from offshore fields in the North Sea to gas treatment plants in the UK or on the European
mainland. The pipeline network to the UK was built at the beginning of the eighties to gather
associated gas and gas liquid found in the oil fields and process them onshore: SEGAL (Shell-Esso
Gas and Liquids) and CATS (Central Area Transmission System) connect the oil fields of the area
and carries the products to St. Ferguson and Tampen (41 bcm/y). The pipeline to the European
mainland connect fields to Emden and Dornum in Germany (Norpipe and Europipe, 58 bcm/year),
Zeebrugge in Belgium (Zeepipe, 67.2 bcm/y), Dunkerque in France (Franpipe 20 bcm/y).
• The South-Western Corridor from Algeria and Libya (total capacity 65 bcm/year, 35.8 bcm
imported)
The North African European gas system is composed of four pipelines. Two from Algeria to Spain
(Maghreb–Europe Gas and Medgaz, 20 bcm/y), one from Algeria to Italy (Trans-Mediterranean or
Enrico Mattei pipeline, 30.2 bcm/y) and the last one from Libya to Italy (Greenstream pipeline, 11
bcm/y).
• LNG receiving terminals (total capacity 186 bcm/year, 69.3 bcm imported)
There are 20 regasification terminals located in eight countries; however, two countries hold the
highest amount of terminal and regasification capacity equivalent to 62% of the total: Spain (6
terminal, 60.1 bcm/y) and the UK (4 terminals, 53.5 bcm/y). The remaining are in France (3 terminals,
23.8 bcm/y), Italy (3 terminals, 15.4 bcm/y) and Belgium, Greece, Netherlands and Portugal (one
terminal each in total 33.6 bcm/y).
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Figure 3.17 – Map of European gas network
The European network evolved and increased its dimensions since the formation of the Union; the
strongest impulse in the evolution of a unified network and the creation of the Common Market were
the European gas directives. The first directive (1998/30/EC) set the base for the common gas market
introducing common standards for transmission and distribution systems and demerging vertical-
integrated company.
Following directives (2003/55/EC) and its final implementation (2009/73/EC, also known as
“third energy package”) shaped the actual structure of the European energy market. Vertically
integrated energy companies were forced to carry on an “ownership unbundling”; a complete
separation of energy generation (or import) sector from transmission and final distribution (valid for
both electricity and natural gas). After this separation, production (or import), distribution and selling
to final costumers were open to concurrence, and companies were forced to sell to the State their assets
in the transmission and distribution networks. Transmission operators became separate companies
(private or state-owned depending on the country) that regulated transmission of natural gas (or
electricity) applying transparent and non-discriminatory criteria to the markets participants. To
enforce concurrence TPA (Third Party Access) was set for all energy infrastructures; the spare
capacity25 of pipelines and LNG terminals is allocated through an open auction on a specifically design
capacity market, final allocation is based on the proposed bid.
25 Is the receiving capacity (for LNG receiving terminals) or the underexploited volume (in case of a pipeline) that remains after the allocation of the volume necessary to cover the existing obligation with the suppliers
57
Despite all the legislative steps towards a common and competitive market, the European market
still present some rigidity and it is still far from United States gas market, the reference model. The
main two differences between the two market models are the reduction in the numbers of suppliers
and the contract rigidity and the presence of a not well-integrated network, both of which strongly
limits the development of the European market. In Europe, the volume of gas produced is not
sufficient to guarantee a concurrence such as the one of the United States and in most part, the reliance
on a limited number of importers and the presence of long-term contracts impose a rigidity that does
not allow price competition. The recent increase in the import of LNG with short-term contracts and
a pricing indexed to the spot price of the main European hubs instead to that of the oil benchmarks
partially contributed to reducing this rigidity, but the share of LNG is still too small to completely
change the market.
Another problem is that each importer negotiates the price with the exporting company
autonomously without any common European scheme; these results in pricing levels that strongly
differ within the union. In a truly open and competitive market, the pricing process is transparent,
information is available to all market participants and the final gas price has two main components:
the market-clearing price26 plus additional transports costs. In Europe, the sealed contracts between
companies are mostly industrial secrets and the pricing scheme and contract clauses are often
unknown. This problem is particularly enhanced in the Gazprom case; its high market share and the
lack of other options give the company a high market power that resulted in its refusal of adopting a
unique and transparent pricing scheme for all the European countries; adopting different contracts for
each importer where, often, foreign policy prevails on business aspects.
As figure 3.16 shows, Gazprom prices in Europe do present a very high variability, which has little
to do with economic aspects and costs associated to gas transportation: the three countries supplied
with the Yamal-Europe pipeline pay different prices that do not depend on the distance covered.
Belarus pays 166 dollars per thousand cubic meters, Germany 379 $/tcm and Poland 526$/tcm. This
pricing has nothing to do with the costs of gas transportation; Poland pays nearly 40% more than
Germany despite being closer to Russia, and thus presenting smaller transportation costs. On the
contrary, transportation costs in the US are clearly defined; any systematic price differential between
hubs depends on the cost of gas transportation. European prices are more related to the political
relationships with Russia.
Gazprom’s dominant position is worsened by the still poor interconnection existing between
European countries: the eastern European network is poorly interconnected and some areas (the Baltic
Republics and Finland) are connected only to the Russian network thus being unable to receive gas
from any other supplier in case of disruption or shortages.
26 In an economic market, market clearing is the process by which, the supply of whatever is traded is equated to its associated demand, so that there is no leftover supply or demand: the total quantity exchanged on the market is called market-clearing quantity and the resulting price market-clearing price. The economic theories assumes that, in any given market, prices always adjust up or down to ensure market clearing.
58
Figure 3.18 – a) Maps of Gazprom import price in Europe b) price and transportation costs in the US hub ($/mBTU)
(IEA, Development of a competitive gas trading market in continental Europe)
The lack of a wide interconnection between European member countries affects all the union
limiting concurrence and making impossible to move volume of gas from neighbors’ countries in
response to a local shortages. Several projects to enhance gas-moving capacity are actually undergoing
in Europe; the transport capacity is, in fact, the milestone of a fully integrate, competitive and liquid
market.
3.4. Future scenario
Future gas consumption within the European Union will depend on essentially on the extension of
the recovery from the 2008 economic crises and the future environmental policies. Environmental
policy would be of primary importance in the case of the power generation sector. Future of CCGT
power plants will depend on the extent of reduction of nuclear power plants and the enforcement of a
stronger regulation on maximum pollutant emission. Political decisions would be fundamental to
incentive gas consumption; based on which decisions would be taken, natural gas could became the
main energy source in the EU-28 or lower its share in favor of other cheaper but more pollutant
options, such as coal.
Elaborating a future scenario involves a high degree of uncertainty due to the numerous factors
involved; in 2012, Eurogas elaborated a long-term outlook to 2035. The three scenarios elaborated are
based on different assumption on the economic recovery and environmental policies.
Base Case scenario: derived from current national energy policies, which show little or no investment
in the gas sector in the next five to ten years.
Environmental Case scenario: based on an increase of renewable production, a slight decrease in
nuclear one, together with restored economic growth and a high rate of innovation in energy-efficient
equipment
Slow Development Case scenario: natural gas become less competitive in Europe as a result of global
developments, hostile policy environment and weak industrial performances together with slow
economic growth and slow progress in energy efficiency
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In 2010, gas accounted for 25% of Europe’s primary energy use; by 2035, the gas share could
increase to as much as 30% (the Environmental Case), or may decline to 24% (the Slow Developments
Case). The main difference between the three cases regarding volumes of gas sales to power plants,
and, indirectly, the environmental policies and reduction in CO2 emission estimate to reach in 2035 -
25% for the base case, -36% for the environmental case and -19% for the slow development case.
Figure 3.19 – Breakdown of European gas demand 2010 – 2035 under the three scenario considered (Eurogas)
The main differences between the three scenarios and main driving factor of an increase (or
decrease) in gas consumption is the power generation sector: an enforcement of stricter environmental
policies would contribute in increasing consumption level.
An estimation of the future consumption is difficult because of economic and policy factors
involved; forecasting future gas production is, on the other hand, easier. Long-term production in
Europe will depend on investment in new exploratory programs that, at the state of the art, are
undermined by local opposition and length of time required to obtain permits. Production from
conventional gas fields is declining and this trend is expected to continue in the future.
An increased the gap between internal demand and supply, enhancing worries related to security
of supply. Those worries are not only related to the presence and the capacity of the current import
facilities but also to the future capacity of the actual exporting countries in covering European needs.
While importing infrastructures exhibits a relatively low degree of saturation, thus being able to face
any increase of imports, major worries regard the capability of producer to keep this level of gas
exports. Norwegian gas fields are expected to exhibit production decline similar to what has been
experienced in the UK, Algerian growing internal demand might reduce the exportable volume and
the import of LNG, despite their forecast increase, would not replace pipeline imports due to high
costs and complexity involved.
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Chapter 4
Shale Gas, an Unconventional Global Resource
Since the last decade, shale gas has become the most important energy issue worldwide. The so-
called “shale gas revolution” has reshaped the energy panorama of the United States and has had a
wide impact on the global energy scenario. The existence of this unconventional formation has been
known for several decades but the technologies available ere not sufficient to allow an economic
recovery from gas-shales thus limiting industry interests in exploiting those resources. Things changed
when new advances in drilling and stimulating technology allowed the profitable extraction of high
volumes of natural gas from shale formation. Technological improvements unlocked an incredibly
vast quantity of oil and natural gas held within the shale formation, dramatically raising the US
hydrocarbon production.
4.1. Unconventional gas
What exactly is an “unconventional gas”?
The term “unconventional” creates a misperception leading uninformed public in thinking that this
typology of natural gas differs from the conventional one, which is, of course, not the case. In general,
conventional resources are easier and cheaper to produce than unconventional ones; however, ease
and costs are not an exhaustive definition. The differences between “conventional” and
“unconventional” lies in the reservoir geology e and in the technologies required to extract the gas.
“A conventional reservoir is a high quality, high permeability reservoir; the reservoir has a loose
structure with interconnected pores where the hydrocarbons can accumulate. To extract oil&gas
trapped in these formations the only thing that has to be done is to drill a vertical hole and perforate
the productive interval, then the natural occurring pressure differential would create a significant
flow that allows a commercial recovery. An unconventional reservoir is a lower quality formation
with low permeability and a poorly interconnected structure, which prevents the hydrocarbons to
naturally migrate to the surface in commercial quantities.” Holditch (2013)
To extract the gas held in those formations, the reservoir has to be “stimulated” through the
creation of artificial pathways between the wellbore and the reservoir with a process called hydraulic
stimulation, or hydro-fracturing (commonly called “fracking”). The process involves the injection of
highly pressurized fluid in the formation to create artificial fractures that allows the movement of the
hydrocarbons. The fluid injected is a mixture of gelified water or foams with sands or composite
material as proppant.
The proppant is necessary to hold open the newly created fractures after the injection pressure is
released; beside water and sand a small amount of chemicals are added to reduce friction and pumping
requirements, improve the fluid transport capacity and stabilize the formation.
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According to this classification, there are three different types of unconventional gas (Figure 4.1)
Coalbed methane (CBM)
Extracted from coal seams; formed during the coalification process (the conversion of peat into
coal) due to the anaerobic decomposition of organic matter and the subsequent fossilization process,
which converts organic matter into thermogenic methane, carbon dioxide, water and nitrogen. Natural
gas is kept within the pores of the coal matrix as adsorbed gas or as free gas in the cleats (natural
occurring fractures in the coal seam). Coal cleats are normally saturated with water that have to be
pumped off before production could start; the removal of reservoir water depressurize the seam
causing methane to desorb from the coal pores and consequent flow into the wellbore.
Tight gas (or tight-sands gas)
Gas extracted from non-associated reservoirs with lower porosity and permeability27 with respect
to “conventional” sandstone gas reservoirs. Reservoir mineralogy is generally variable (usually
sandstones or siltstones, but also includes carbonate rocks and sandy shales) so those are all described
as natural gas reservoir that cannot be developed profitably with conventional vertical wells, due to
low flow rates and require massive hydraulic fracturing to make the well produce at economic rates.
Contrary to CBM and gas shales tight sands are only the reservoir rock and do not generate the
hydrocarbon they held.
Shale Gas
Natural gas found in organic rich, fine-grained sedimentary rocks composed of mud, flakes of clay
minerals and tiny fragments (silt-sized particles) of other materials, in particular quartz and calcite.
These shales or mudstones contain a high amount of organic matter that evolved in kerogen generating
hydrocarbons; thus, gas shales are the source rocks of all the hydrocarbons found in conventional
deposits. The deposition mechanism generate a highly compact and laminated rock with extremely
low permeability28. Natural gas is stored as free gas within shale pores, in the network natural
occurring fractures, or adsorbed onto the shale minerals and organic matter composing the rock.
Overall porosity in gas shales is higher than conventional sandstone but the dimension of a single pore
is are much smaller: the gaps connecting the pores are only 20 times bigger than a single methane
molecule. Therefore, gas shales could store a high amount of gas, which is unable to move because of
the ultralow matrix permeability. In order to extract the gas massive stimulation process is needed in
order to generate a system of microfractures that artificially increase matrix permeability allowing the
movement of gas molecules.
27 Generally less than 0.1 millidarcy (mD). To have a comparison conventional reservoirs have a permeability that ranges
from 10 mD (medium quality reservoirs) to 1000 mD high-quality reservoirs. 28 In the order of 10-20 nanoDarcy, nearly ten times lower than tight reservoir.
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Figure 4.1 – Schematic cross-section of general types of oil and gas resources (EPA, 2014)
Besides these three typology, a fourth one exists called methane hydrate or gas hydrate. Methane
hydrates are solid clathrate compounds29 where large amount of methane is trapped within the crystal
structure of water, forming a solid similar to ice. Originally thought to occur only in the outer regions
of the Solar System methane clathrate have been found on the Earth ocean floors and in the permafrost
of some artic regions. Due to the adverse conditions required to their formation, determining the total
quantity of gas present worldwide is almost impossible but, apparently, could be several times higher
than the known gas reserves. However, the commercial exploitation of this resource seems incredibly
challenging and it would not be feasible in the near future. Most of the research carried out on methane
hydrates and their behavior is related to the hazards that these formation poses in the ultra-deep
offshore. Methane hydrates forms under specific condition of pressure and temperature and will easily
dissociate into liquid water and gaseous methane when conditions exist from so-called hydrate
envelope. This dissociation creates a sharp increase in volume that, if happened in a confined space,
could lead to potentially catastrophic results. Apparently was the formation of methane hydrates and
the successive volume expansion in a well that caused the explosion of the offshore platform
“deepwater horizon” and the consequent oil spill in the Gulf of Mexico. (Macondo oil spill, April
2010).
29 A clathrate is a chemical substance consisting of a lattice that traps or contains molecules.
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4.2. Estimation of Global Resources
None of the unconventional gas is a “new discovery” but have been known for long time. Natural
gas in coal seams have always been one of the major danger of coal mining while shale rocks were
known to be the source rock of all the conventional formation. Nevertheless, because of their high
extraction costs and the relative abundance of cheaper oil and gas, those formations never attracted
industry interests; the few wells drilled were mostly pilot exploration or projects founded through
government or federal agencies. The recent US boom spurred interest in unconventional gas formation
and many other countries worldwide started investigating their own shale sources aiming of
replicating the US “miracle”. However, because of the novelty of the topic, only little reliable data
regarding some shale formation exists and the estimation of global unconventional gas sources is far
from being exhaustive and accurate.
The most recent estimation was an article published in 2013 (Mc. Glade at al.) reviewed all the
original estimation of global unconventional gas. There exist only 69 original studies most of which
(49) were published after 2007 none of which gave a comprehensive analysis of global sources but
rather a single-resource evaluation on a regional scale. Particularly in the case of shale gas, the lack
of production data outside North America combined with a poor knowledge of the geological
characteristics of these formations made the estimation highly speculative. Estimation of gas in place
and recoverable resources are based on weak initial hypothesis and performed as analogy with similar
formation in the US.
Although no reliable estimate of global resources exist (which, has to be said, also happens for
conventional sources) the amount of unconventional oil and gas present on earth is certainly an order
of magnitude higher than conventional one. All natural resources follow a lognormal distribution with
an inverse relationship between the quality of a deposit and the frequency with which those deposits
occur in nature.
Figure 4.2 – The natural gas resource triangle (IFP Energies Nouvelles - IFPEN)
The “resource triangle” graphically express this concept: high-grade deposits on top of the triangle
are small, difficult to find but easy to extract while worst quality deposits are much larger but also
65
more complex to produce requiring better technology and higher investments. Low quality oil and gas
reservoirs are difficult to develop but the upside is that these reservoirs will contain more hydrocarbons
than what has been found find in conventional oil and gas reservoirs.
The following picture gives an overview of the natural gas resources worldwide dividing them by
region and gas typology.
Figure 4.3 - World natural gas resources classified by typology and world region (IEA, WEO 2013)
Some clarifications on the terminology employed are necessary; “proven reserves” (green bar)
refers to discovered resources that recoverable with current technology and commercially valuable
under current economic condition while “other recoverable conventional gas” (pink bar) includes the
recoverable sources which are subeconomic and deposit that have a high probability of being present,
although not yet discovered. “Recoverable unconventional” indicates the best estimation regarding
existing on the quantity of estimate unconventional gas in place that could be extracted with current
technological level.
The only world regions where conventional resources are higher than unconventional ones are
Russia and the Middle East. This, however, depends on the lack of studies focusing on this two world
region. In fact, the latest and most reliable estimation of shale gas global sources (Eia & ARI, 2013)
deliberately ignored regions with large quantities of conventional gas reserves. This implies that the
available studies are likely to underestimate the global recoverable sources of shale gas: in the US,
the quantity of gas in place in tight or shale formation outtakes the one held in conventional deposit
with a ratio that is nearly 10 to 1. The major oil and gas provinces in the world, like Middle East and
Russia, are expected to hold extremely large volumes of oil and gas in unconventional reservoirs
waiting to be discovered and developed.
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4.3. Shale Gas
Since the improvement in the knowledge of earth geology and petroleum formation model,
geologist had found evidence of oil and natural gas present in reservoirs with different geological
characteristics with respect to the “conventional” ones. In fact, organic-rich shale formation were
known to be the source rock of all the oil and gas accumulation exploited until that day.
Figure 4.4 - Black shale rock and shale outcrop deposit
Shale rocks were investigated by the oil&gas industry in relation to their role as seal rock (due to
their extremely low permeability) and for they role as source rock, fundamental to develop better
petroleum play reducing the uncertainty associated with conventional exploration. Improvements
made in this model revealed that organic-rich shale were not only the source but that large amounts
of generated hydrocarbons were retained within the rock. According to petroleum system models
(Leythauser D. and Hunt J.M.) only 50-75% of the hydrocarbons generated by the source rock is
expelled from the source rock. While 25% of the total might seem a low percentage, it has to be
compared with the percentage that is found in conventional deposits. The large amount of hydrocarbon
expelled is lost during the migration process, through retention in the rocks strata or surface seepage,
and less than 10% of the generated accumulates in conventional deposit.
Despite the high quantity in place, the recovery of hydrocarbons held in extremely compact and
tight formations was a major obstacle that required substantial improvement in technology employed
and, in addition, was all but commercially valuable. Gas recovery from shale formation is based on
two key technologies: horizontal drilling and hydraulic fracturing; none of these two were a scientific
breakthrough but it was their combination, so-called “massive horizontal stimulation” that made the
extraction economically feasible. Horizontal drilling is the evolution of the “directional drilling”, a
drilling methodology was developed during the off-shore exploration to allow the reach of deposit
located away from the straight vertical of the drilling pad placed on the platform. Likewise, hydraulic
fracturing was a reservoir stimulation technique patented in 1947 and was widely employed to
stimulate conventional field and enhance their productivity; fracturing portions of the reservoir around
the borehole increases permeability allowing a higher recovery rate and increasing well lifetime.
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4.3.1. Shale gas generation process
Shale rocks is the most abundant sedimentary rock present in the earth crust but, trivially, not all
of them held oil or gas. The hydrocarbon generation potential depends on the amount of organic matter
present. Organic richness in shale rock is measured by the weight fraction of total organic carbon
(TOC); most gas-bearing basin exhibits a TOC range that varies between 2 and 10%. A percentage
below 0.5% conventionally indicates a shale rock with almost no hydrocarbon generation potential
while basins with TOC in the range of 0.5-2% could still be good source rocks making up what they
may lack in organic richness by being thicker or more laterally extensive thus exhibiting a higher
sheer volume.
Nevertheless, high percentage of total organic carbon do not guarantee a high quality reservoir
since the generation of hydrocarbons also depends on the typology of organic matter and its maturation
history. The hydrocarbon generation process is a complex series of chemical and biological reactions
that transform the sedimentary rock into source rock: it could be summarized in the following steps
(Mahlstedt and Horsefield, 2012):
Figure 4.5 – The process of hydrocarbon generation trough thermal maturation of source rock (Hunt, 1995)
Diagenesis
A low temperature (50 – 75°C) alteration step during which oxidation, biological degradation and
other chemical processes begin to break down organic material altering its composition. In this
temperature range, bacterial decay produces biogenic methane while organic material is gradually
converted into kerogen.
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Catagenesis.
As burial depth increases pressure and temperature raise: when temperature exceeds 70°C thermal
decomposition (cracking) of kerogen begins producing lightweight hydrocarbons (oil and natural gas
condensate). Further temperature increase above 150°C cause secondary cracking of oil molecules,
producing additional gas molecules and carbon-rich coke or pyro-bitumen.
Metagenesis.
In the last step, temperature reaches 150-250 °C and kerogen is totally transformed into dead
carbon and light hydrocarbons (wet gas); during this phase some non-hydrocarbon gases (CO2, N2
and H2S) are released.
The alteration of the organic matter in the buried rock layer is commonly called “thermal
maturation”. The chemical composition of kerogen changes through thermal maturation process. As
the generation of hydrocarbon perceive the hydrogen present within kerogen is gradually depleted;
after total hydrogen depletion, generation of hydrocarbons ceases naturally, leaving a carbonaceous
residue. Hydrocarbons generation increases internal shale pressure resulting in part of the gas and oil
being expelled and migrating upwards into other rock formations, where it could accumulate forming
conventional deposits. Eventually the increases in the internal pore pressure will occasionally build
up to the level of natural rock fracturing, in this case the shale presents itself with a network of small
fractures occupied by oil or gas molecules.
Figure 4.6 – Shale rock turning into a gas-shale source rock (Resource Play)
The onset of hydrocarbon generation as a consequence of kerogen thermal maturation depends on
the typology of organic matter and its deposition environment that are summarize in the kerogene
type. Deposition environment and type of organic matter determines the chemical composition of the
organic sediment and have a great influence on the hydrocarbon production, in terms of both final
product and relative yield. The two key factors are the amount of oxygen and hydrogen present
compared to the quantity of carbon, the so-called hydrogen/carbon ratio and oxygen/carbon ratio.
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Table 4.1 – Types of Kerogen and their hydrocarbon generation potential
Kerogen
Type Main Source Material
Deposition
Environment
H/C
ratio
O/C
ratio
Generation
Potential
I Algae Lacustrine >1.25 <0.15 oil
II Plankton Marine <1.25 0.03-0.18 oil and gas
III Higher plants Terrestrial <1 0.03-0.3 Coal and gas
IV Reworked, oxidized material Varied <0.5 - No potential
Different H/C and O/C ratio in the kerogene reflects the difference in organic source material and
sedimentary environments; therefore, determination of the kerogen-type is an essential first evaluation
to understand the expected products, gaseous or liquid hydrocarbons.
Type I originates from lacustrine, and anoxic environments, resulting in very high H/C ratio.
Consequently has the largest hydrocarbon generation potential first as liquids (oil) and later as gas.
Type II Kerogen derives from marine plankton-bacteria organic matter and is the most common
in shale formation
Type III derives from land-plant debris from continental run-off into sedimentary basins; has a
lower H/C ratio; generates low amounts of hydrocarbons, mostly in the form of methane gas (CH4).
Type IV Kerogen is composed of residual (“dead”) organic matter left from partial oxidation and
alteration processes happening during sedimentation. This material has almost no hydrocarbon
generation capacity and, due to the initially high O/C ratio from partial oxidation, it release CO2 in
the course of its diagenesis.
Beside the typology of the kerogene and the quantity of organic matter present, another
fundamental factor is the maximum temperature sediments have been exposed to: in general the higher
the temperature the lighter the final product. Shale’s “thermal maturity” plays a key role for HC
production from shales: both subsurface temperature and geologic time spent at or near maximum
subsurface temperature play a role in the “evolution of maturity” of the shale. The higher the
subsurface temperature and the longer the geologic time at this temperature, the higher the thermal
maturity of the shale. Shales need to be exposed to higher subsurface temperatures over elevated
geologic time to generate and produce oil and gas from the kerogen. However, despite the existence
of a linear relationship between depth of burial and temperature shale depth of burial is insufficient to
comprehend its thermal evolution. In fact, shale strata could have been buried deeper and brought
toward the surface by the earth crust movement or it could have experienced higher temperature due
to thermal anomalies such as volcanic process or proximity to slipping faults. The only way to measure
shale maturity is through the analysis of the rock vitrinite reflectance. Vitrinite is a type of woody
organic matter present in coal and sedimentary kerogene that changes in a predictable manner
according to the temperature it is exposed. Determine the vitrine reflectance of an organic sediment
allows to identify the maximum temperature to which the sediment have been exposed during its
burial history. Vitrinite reflectance measures the percentage of reflected light of a rock sample express
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as a percentage of the same reflectance when immersed in oil, %Ro (percentage reflectance in oil).
The onset of the oil window (c.a. 50 °C) is correlate with reflectance of 0.5-0.6% while the termination
(c.a. 150 °C) with values of 0.85-1.1%; gas window (150-250 °C) is associated with values in the
range of 1.0-1.3% to 3.0%. Figure 4.7a) shows the Van Krevelen diagram illustrating the complete
thermal evolution of kerogen from the initial high atomic H/C – O/C values towards the over-mature
conditions with a residual kerogen of very low H/C-O/C ratios. Temperature in the graph is indicated
with the increasing percentages of %Ro.
Figure 4.7 – a) Van Krevelen diagram, b) scheme of hydrocarbon generation and yields (Resource Play)
Figure 4.7b) describes the evolution of the hydrocarbon generation process; minimum subsurface
temperature needed to onset the hydrocarbon generation is of 50-60°C. Oil generation is maintained
in the 100-150°C window and, beyond this temperature threshold, fades is favor of the more thermally
stable methane gas. Finally, the kerogen’s total hydrocarbon generation capacity is exhausted at a
level between 250-300 °C; at this point, the remaining kerogen is “burnt out” and turns into a carbon-
like residue with very low atomic H/C – O/C ratios. The thermal evolution pathways for the kerogen-
types affect, firstly, initial O/C ratio due to the production of CO2 and CO. At higher temperatures,
the H/C ratio is progressively lowered due to the formation and subsequent release of hydrocarbons
from the kerogen. This thermal kerogen cracking along with HC generation is associated with
considerable structural change of the kerogen towards a hydrogen-poor mature and over-mature
kerogen structure; roughly, the evolution of all kerogen types could be described as:
Kerogen Immature Kerogen Mature + oil Kerogen Late/Overmature + gas
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The storage mechanism in shale formation includes the presence of free gas trapped in the natural
fractures and the pores or as gas adsorbed on the surface of the organic clays or within the kerogen.
The amount of both free and adsorbed gas per unit mass increases increasing total organic carbon
content (%TOC) or pressure (i.e. depth of burial. Figure 4.8 shows the amount of stored gas in relation
to formation pressure. At low pressure (shallow depth), the main mechanism is adsorption (orange
line); the increase of temperature shows a slow increase in the adsorbed gas which reflects an
asymptotic behavior based on the Langmuir isotherm. Free gas, instead, depends has an almost linear
relationship between pressure and amount of volume stored thus being the main storage mechanism
in deep shales. The total quantity of gas is important but while, free gas composes early production
adsorbed one becomes important once the bottomhole pressure experience significant decline.
Adsorbed gas is recovered with lower flow rate but, being present in higher quantities, it maintained
a steady flow for years; some pilot shale wells drilled in the Barnett in the mid ’80 show a steady flow
after almost thirty years of production.
Figure 4.8 – Adsorption Isotherm, Gas Content vs. Pressure (Alexander T., 2010)
Shale formations cover very large geographic areas and are commonly refers referred to as “shale
basin”; however, only portions of the basin have the required characteristics (such as organic content,
thermal maturity and thickness) to allow a commercial recovery of the hydrocarbons, those parts are
called "plays". Shale basins do exhibits an extreme variability in the lithological characteristics due to
the difference in the deposition process (by different depths of the stagnant water body or its proximity
to the land) and to the different diagenesis process (intense rock layer folding, faulting or for
subterranean volcanic activities). If the rock strata has undergone a complex and non-homogenous
deposition history because of intense folding or slipping of natural faults shale characteristics could
vary widely across the same play.
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4.3.2. Resource estimation and global availability
The estimation of the amount gas or oil in place in every world basin could be carried out
essentially in three ways: through an analogy with developed and well-known shale plays, with a
bottom up analysis of geological parameters or through the extrapolation of production data. First
methodology estimates the area and thickness of the selected shale basins and calculate the estimates
gas in place through an analogy with one of the US shale gas basin. Despite the relatively crude
methodology, these estimates formed the basis of nearly all the studies and estimates performed
outside North America until 2009. Second methodology is based on the extrapolation of production
data in order to estimate the EUR (Estimate Ultimate Recovery) of a well and extending it to the whole
basin. This approach is based on a statistical fit of the declining curves of a group of wells to their
historical production and future extrapolation that gives the total EUR. This approach requires a
significant amount of data on historic production from multiple wells within the basin and could be
applied only in regions where production is relatively well established.
Because no commercial recovery as yet started outside north America, n the rest of the world
estimates of shale gas in place are performed with the third and last method called “bottom-up
geology” approach. The whole basin is analyzed in terms of total organic carbon (%Wt) and thermal
maturity (%Ro) to identify prospective areas; once the prospective area is identified the estimated oil
and gas in place could be calculated. To calculate original gas in place (OGIP sm3gas/tonshale) several
data are required: the volume of the prospective play (areal extension multiplied by the average
thickness), gas-filled porosity30, temperature and pressure31 of the formation. The calculation is
performed with coefficient to account for non-ideal behavior of the hydrocarbons and their dimensions
in comparison with shale pore size. Once the original gas in place is determined this number is than
lowered to account for the uncertainty present in the estimation obtaining the ‘risked gas in place’.
Two factors are employed to lower this evaluation: ‘Play Success Probability Factor’ that accounts
for the lack of reliable geological data and the ‘Prospective Area Success Factor’, which combines a
series of concerns that could relegate a portion of the prospective area to be unsuccessful or
unproductive. In the last step, a percentage ‘recovery factor’ is applied to estimate the technical
recoverable resource (TRR): the recovery factor, reflects the estimated proportion of (risked) OGIP
that is considered technically recoverable. This factor is chosen based on shale mineralogy
(ductile/brittle), properties of the reservoir (pressure level) and geological complexity of the formation
and range between favorable (25%) or less favorable (15%). As a comparison, recovery factors for
conventional gas deposit could be as high as 80%.
30 Shale pores are considered all filled up with natural gas, liquid hydrocarbons or formation water; those data are obtained analyzing rock cores sample or, if not present, estimated based on the porosity data of similar basin 31 Which are, a part from geological anomalies, linear function of basin depth
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Figure 4.9 – Schematic representation of the steps used in the geological based approach. (Adapted from Mc Glade
et Al.)
Figure 4.11 illustrates the best estimate made for the technically recoverable shale gas resource
for different world regions present in the latest and most comprehensive paper on this topic (Eia &
Ari, 2013). As previously mentioned the low amount of shale gas resource in the Former Union and
Middle East depends on the absence of reliable and intensive studies in those world regions. Europe
has the smallest amount of shale resources but the technically recoverable ones are nearly three times
higher than proven gas reserves
Figure 4.10 –World estimate natural gas resource (Bp, Eia & Ari)
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4.4. Shale gas extraction process
Despite the presence of higher amount of gas in place, the main problem with shale gas
exploitation is the extraction process that involves higher technological complexity and higher costs
with respect to conventional gas.
4.4.1. Exploratory phase
Shale gas basin have a large areal extension so the aim of the exploratory phase is not finding
geological formations that might contain an oil or gas reservoir (seal, trap and reservoir rocks) that
are known to be there but, ,but in identifying the area where a shale well would have the higher
production (the so-called “sweet spot”). The main tool employed is the 3-D seismic imagining: trough
the analysis of the wave velocity, its reflection and the delay time geophysicist are able to obtain a
map of the subsoil rock strata with their relative characteristics. In conventional hydrocarbon
exploration, seismic reflection is used to identify the trap above the field and the field above and to
identify the different area within the field (gas, liquid hydrocarbon, water). Seismic data are analyzed
to understand the formation geology such as lithology of the strata, dimension and position of the
aquifers and the eventual presence of natural fractures but do not give any information regarding the
quantity of hydrocarbon held within the shale. To assess the quantity of hydrocarbons present, a test
well has to be drilled and through well logging32 and lab analysis of shale rock cores; if the lithology,
mineralogy, total organic content, thermal maturity and total quantity of absorbed gas are prospective
the exploitation could begin.
4.4.2. Site preparation
Once the area has been analyzed and the well location has been chosen, the site have to be prepared
for the drilling and fracturing activities. First, a level site must be created; the first soil strata is
removed in order to compact the ground allowing resistance to the weight of the drilling equipment.
Soil is removed and stockpiled on the border of the drilling site to be used as a burn (similar to a dike
or pond dam) to prevent water flowing over the location, it also act as a partial view and sound barrier.
The soil will be used for site reclamation after the well no longer produces hydrocarbons in
commercially valuable quantity. After the completion of the soil containment walls the walls are
hydro-mulched33 to promote vegetation growth of vegetation stabilizing the walls preventing erosion
or collapse. Once the well site is levelled, the drilling rig could be move at the site and assembled.
32 Well logging, also known as borehole logging, is the practice of making a detailed record (a well log) of the geologic formations penetrated by a borehole. The log may be based either on visual inspection of samples brought to the surface (geological logs) or on physical measurements made by instruments lowered into the borehole (geophysical logs). 33 Hydro-mulching (hydro seeding or hydraulic mulch seeding) is a planting process that uses a slurry of seed and mulch to promote vegetation growth on large areas such as hillsides and sloping lawns to prevent erosion.
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Due to its complexity and dimensions, the rig has to be moved on site by specialized trucks that are
heavier than normal ones. Because of the truck load during rig and other equipment transportation
access road have to be suited to sustain high weight and, if not, have to be reinforced. Once the drilling
rig is erected, a trench is dug around the drilling perimeter and the floor is covered with impermeable
membrane and plastic blocs to ensure the containment of any potential spill avoiding any infiltration
into the ground soil. When the drilling site lies in proximity of a residential area, a sound absorbing
barrier has to be erected to mitigate the negative noise impact of the drilling operation. Site preparation
takes up from three to five days and is limited to daylight hours, once drilling begins operations
continue without interruption 24/7.
Figure 4.11 – Drilling site in the Marcellus shale, Pennsylvania
4.4.3. Well drilling and completion
Once the site set-up is concluded, the drilling phase begins: the drilling operation could require
approximately 21 to 28 days depending on the depth of the target shale and geological complexity of
the formation. Typical wells are drilled in several stages with decreasing dimension of the drilling bit
and the borehole. Because of the high areal extent of shale formations in comparison with their
thickness, wells are typically drilled horizontally to increase the contact volume with the reservoir.
The borehole remain vertical until 150 to 300 m above the target shale formation (kickoff point), then
the drill bit proceeds in an arc until it intersects the target formation (entry point) to continue
horizontally for about 1 to 2 kilometers. Before the beginning of the actual drilling operation, a large
diameter hole is created for the first 15 to 30 meters and a steel pipe called conductor casing is inserted
and cemented into place.
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Conductor casing stabilizes the ground around the borehole and acts as first layer of protection
separating the wellbore from the private water wells and help. After each portion of the well is drilled,
the bit is proceed withdrawn on the surface and a nested steel protective casing is inserted and
cemented into place. The cemented steel casing ensures the absence of any contact between the
borehole and the surrounding formation, especially aquifers, porous sandstone formation, which
contain fresh water. Since in the rural area no connection with the aqueduct is, these aquifer represent
the only source of drinkable water; therefore, any potential infiltration of hydrocarbons has to be
avoided. In order to minimize contamination risk the firs drilling phase, when the drill bit passes
through the water table, employs air-drilling34 instead of the conventional mud. To ensure the stability
of the borehole and to protect the surrounding deep freshwater zone a secondary layer of steel casing
(called surface casing) is inserted into the borehole, installed and cemented within the surface casing.
After the surface casing is set into place a blowout preventer is installed; the blowout preventer is
composed of a series of safety valve and seals placed on the top of the well casing in order to control
pressure and prevent surface release of hydrocarbons in case of pressure unbalance or accidents.
Next, a smaller drilling assembly is lowered in the borehole through the surface casing: at the
bottom of the casing, the bit drill through the cement towards the gas bearing formation. The drilling
methodology employed below the surface casing uses drilling mud that is pumped through the drilling
bit and ejected at high pressure by special nozzles in front of the drilling bit. The drilling mud is a
non-hazardous water-based mixture with a synthetic thickener that acts as a coolant, lifts the rocks
cutting out of the hole and onto the surface, stabilizes the wall of the borehole and act as pressure
control; controlling kicks35 and avoiding blowouts.
A few hundred meters (between 100 and 300) above the target shale formation the drilling
assembly is stopped and the entire string is retracted to surface to be replaced with a special drilling
system able to bend and deviate the drilling bit until plain horizontal. This point is called kickoff point
and from that point, the drilling bit is steered and deviated to reach shale formation horizontally.
Because of the high permeability of shales formation, e of the key to a commercial exploitation is
the amount of formation contact volume; for this reason, the well goes horizontally into the formation
for about 1 to 2 kilometers to increase contact area. Once the horizontal segment of the well is
completed the whole equipment is retracted to the surface, a small steel pipe called production casing
is installed throughout the total length of the well and cemented in place. Cement creates an additional
barrier between the production casing and the surrounding rock strata ensuring that the hydrocarbons,
once free to move outside shale formation, could only flow into the production casing.
34 Air drilling (also known as pneumatic percussion drilling) is a drilling technique in which gases, usually compressed air
or nitrogen, are used to cool the drill bit and lift the cuttings of a wellbore in place of conventionally used liquids. 35 A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face. The greater formation pressure has a tendency to force formation fluids into the wellbore. An uncontrolled kick that increases in severity may result in the ejection of formation fluid from the well, what is known as a “blowout.”
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Once the cement is set in place all drilling equipment is retreated, pressure tests are run to ensure
the correct cementing job.
Figure 4.12 – Casing and cement job in a shale well, schematic and cross section (Chesapeake Energy)
Since the onset of the oil and gas industry, drilling rigs were built on site and dismantled to be
transported to another location and then reassembled there. The shale gas boom generated the
necessity of constantly drilling a high number of wells forcing operators to cut the time required to
assemble and disassemble the drilling rig by improving its mobility. “Pad" drilling techniques allows
rig operators to drill groups of wells more efficiently. once the first well is drilled, the fully constructed
rig can be lifted and moved a few meter over to the next well location. Today, a drilling pad may have
five to ten wells, which are horizontally drilled in different directions covering a very large area with
minimum surface foot print. The benefit of a drilling pad is that operators can drill multiple wells in
a shorter time than they might with just one well per site, thus cutting drilling time and associated
costs and improving the overall efficiency.
Figure 4.13 – Horizontal shale gas wells, cluster configuration (TOTAL)
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4.4.4. Hydraulic fracturing
equipment. Simple drilling horizontally through the shale formation will not make the gas or oil
held within the shale flow to the surface, because of the extremely low permeability of shale rocks,
they have to be stimulated in order to artificially create a pathway for the recovery of the gas. So, once
the drilling process is completed, the drilling rig is dismantled, removed from the location and replaced
with fracturing equipment.
Figure 4.14 – a) Hydraulic fracturing equipment in a shale well in the Marcellus shale (Pennsylvania)
b) Schematic illustration of the hydraulic fracturing process (ALL Consulting)
First, a pathway between the borehole and the shale formation has be created; the production casing
and the cement now separating them have to be perforated before the actual fracturing job could begin.
A conveyed perforation gun is lowered until the end of the horizontal section; the explosive charges
are triggered creating a connection between the wellbore and the shale formation. These small-induced
fractures are called “perforation clusters” and are normally 6 to 24 according to the length of the
horizontal section and the formation geology. Perforation clusters, and consequently fracturing stages,
are not spaced equally but rather placed according to the amount of natural induced fractures already
present in the shale formation. In fact, the hydraulic fracturing process works at best when the mixture
pumped infiltrates the network of natural fractures in the shale and opens them rather than forcing the
creation of new ones. Positioning the perforating gun is then a crucial part of the process that could
lead to higher production.
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In order to accurately choose where to place the fracturing gun, gas detectors are employed; gas
detectors are placed on the drilling mud aspiration pumps, which are able to detect the presence of
hydrocarbons within the mud that is flowing back to the surface. Through a time-delayed analysis,
operators are able to associate the amount of hydrocarbons present in the drilling mud with each
section of the horizontal borehole and thus decide where to place the fracturing stages.
Once the cluster are perforated all along the length of the horizontal branch the perforating gun is
retrieved to the surface, the rig is dismantled and replaced with the hydraulic fracturing equipment, a
number of high pressure pumps and blenders. In the commonly employed process of slick-water
hydraulic fracturing, a high-pressure (34.5 – 100 MPa) fracturing fluid, consisting of water, sand and
chemicals additives, is pumped into rocks. The amount of fluid required and exact composition
depends on the specific characteristics of the shale deposit, operational conditions and operators and
varies from a minimum of 2.8 million gallons (10.6 million liters) in the Barnett Shale (Texas) to a
maximum of 5.7 million gallons (21.6 million liters) in the Haynesville Shale (Louisiana). The
volumetric composition of the fracturing fluid is typically 90 – 95% water (abstracted from surface-
water water bodies such as rivers or lakes), 5 – 9.5% proppant (commonly silica sand) used to keep
the induced fracture open once pressure is lowered and fluid pumped back on the surface and 0.17 –
0.5% of chemical additives used to improve the fluid characteristics.
Figure 4.15 - Typical volumetric composition of fracturing fluid (ALL Consulting)
The chemical additives includes:
Acids (5% hydrochloric acid) to remove cement, minerals from the borehole providing an accessible
path to the shale formation.
Friction reducers (polycrylamide polymers) to reduce friction, reducing pumping pressure and
energy consumption.
Surfactants (ethylene glycol) to lower surface tension of the fracturing fluid.
Clay stabilisers (potassium chloride, KCl) reduce clay swelling when exposed to water preventing
the reduction of the shale deposit permeability.
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Gelling agents (guar gum or cellulose) to increase viscosity of fracturing fluid, increasing, thereby,
its ability to transport the proppant.
Scale inhibitors (calcium sulphate) to prevent the precipitation of scales (inorganic partially soluble
salts forming during the mixing of injected fluid and formation water). Scale tends to precipitate and
build up either in the contact area between borehole and shale formation, reducing its permeability, or
inside production tubing reducing the available cross section and thus the production rate.
pH adjusters (organic acids or salts) maintain the pH value of the fracturing fluid within the limits of
stability of the chemical additives employed.
Breakers (e.g. sodium chloride) activated by the high temperature inside the formation allow a time
delayed reduction of the fracturing fluid viscosity. The fluid injected as a gel with the proppant
particles suspended is thinned and flows back to the surface leaving the proppant in place.
Crosslinkers (e.g. Borate salts) maintain fluid viscosity as temperature increase then, once in the
formation, combine with the “breakers” to generate the gel-breaking effect.
Iron controllers (citric acid) to prevent precipitations of metal oxides within the production pipe
Corrosion inhibitors (benzalkonium chloride) also called oxygen scavenger removes oxygen
particles from the water preventing the corrosion of metal surfaces such as well casing and tubing.
Biocides (glutaraldehyde) eliminate bacterial growth in water and gel; bacteria can produce hydrogen
sulphide, which is an extremely toxic gas and can result in reservoir souring, metal corrosion.
The fracture treatment is the key of shale gas extraction and, because of its importance, has to be
carefully monitored and planned to obtain the highest number of fractures within the formation.
Because of the high complexity involved in the fracturing process and the lack of reliable analytic
model to forecast and model the fracture, propagation into the shale the process is based on “trial and
error”. Each shale basin behaves differently because of its lithology or the unique geological properties
(stresses, presence of faults, natural induced fractures) the first hydraulic treatment performed is
carefully monitored in order to determine the response of the formation and optimize the following
treatments. A series of sensors inserted into a vertical test well which is able to record the sound wave
(micro seismic events) made by the fracturing rocks and elaborate them into a graphical plot (called
“fracmap”) to understand how fractures propagate. Beside the direct monitoring, the fracking crew
analyze the growth of fracs in the shale analyzing the pressure response of the formation optimizing
fracturing parameters (slick water pressure, slurry flow rate and proppant flow rate). Fluid is injected
at first without proppant and the pressure is raised until a spike (called break pressure) that indicates
the formation of the first fractures. Right after the break pressure a small amount of proppant (called
the pad) is added, pressure is kept constant and fluid rate is increased allowing the fluid to enter the
formation, opening up the small naturally occurring fracture in shale along the natural zone of
weakness into shale. The slurry rate is then gradually increased until designed value; to this point on
pressure and flow rate are kept constant while the fracture network propagates.
Based on the data recorded by the geomicrophones and knowledge of formation behavior proppant
is added in increasing quantity until the end of the process.
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Figure 4.16 – a) Microseismic event location for a horizontal hydraulic fracture treatment (Esg solution)
b) Fracstage diagram (Arguijo et Al.)
During all the fracturing treatment, water is constantly absorbed by the shale formation; this
absorption process by the shale is the real limit to fracture expansion. In fact, from the base to the tip
of the open fractures the water amount and pressure is constantly reduced decreasing fracture
dimensions (fracture width); once the water on the tip of the fracture has been absorbed, the process
has to be interrupted. Once at this stage the very last part of the treatment, called “flush out” is
performed; density and carrying capacity of the water is progressively decreased and water is pumped
out of the formation along with all the leftover proppant. The proppant left in the fractures prevents
their closure under the hydrostatic pressure of the rock strata, creating an artificial pathway natural
gas to flow.
At the end of the fracturing operation the fluid (commonly called flowback water) flows back out
the top of the well; because of the absorption in shale formation flowback is normally the 25-60% of
the overall volume injected. The flowback fluid is a mixture of water with fracturing chemicals, traces
of hydrocarbons, minerals, salt dissolved and naturally occurring radioactive materials (NORM36)
present in the formation water. This water solution is classified as industrial waste and has to be
treated. Flowback water could be treated on-site and recycled for others fracturing operations; the
choice depends upon the quality of the flowback water and the economics of other management
alternatives. Flowback water that is not reused is managed through disposal; brought to a private or a
municipals treatment plant able to treat water with a high salt content and then discharged into the
water stream. The chemical composition of the water produced from the well varies significantly
according to the formation and the time after well completion; early flowback water resembling the
hydraulic fracturing fluid but later converging on properties more closely resembling the brine
naturally present in the formation. Once the flowback water is recovered, production could begins and
site is restored leaving behind only the production necessary equipment: production tree, separator,
production tanks and the SCADA system used to monitor the well.
36 Naturally Occurring Radioactive Materials (NORM) are radioactive elements (uranium, thorium, potassium or any of their decay products) naturally present in very low concentration within the earth’s crust.
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Figure 4.17 – Production site of a shale well in the Marcellus area (Pennsylvania)
During all the well lifetime small amount of formation water is brought to the surface together
with the hydrocarbons. The mixture is sent to a separator, which recovers the dry gas, sending it to
the gas network while liquid fraction (formation water and liquid hydrocarbons) are stored in designed
tanks on site to be further process or disposed of.
4.4.5. Shale gas production
The natural gas production from shale well begins a few days after the fracturing job, once the
major quantity of fracturing fluid flowed back to the surface and could continue for more than a
decade. Typical production profile of a shale well is showed in the figure below (fig. 4.19). It exhibits
a burst of initial production, given by the amount of free gas stored into the natural fracture that is
released, followed by a steep decline. The steep decline is due to the depletion of the free gas and it is
followed by a long period of relatively low production (commonly around 10% of the initial
production) associated with the production of adsorbed gas; as the pressure in the wellbore decreases
methane desorbed from the organic matter within the shale flows to the surface. The decline
experienced as well as the quantity of producible gas over the well lifetime varies greatly from well
to well even within the same area of a shale play. This high variability is due to the particular
characteristic of the reservoir and its high heterogeneity as well as the effectiveness of the stimulation
process. Despite improvements in EUR and average production, shale gas wells experience a much
higher decline with respect to conventional ones. Shale-gas wells in the USA typically produced 80 –
95% less gas after three years; then the well experienced a sort of “production plateau” with a very
low decline rate. Because large-scale shale gas production has only been occurring very recently, the
production lifetime of a shale well is still a hardly debated topic: most of the analysis set the average
life of a shale gas well from 8 to 30 years. It has to be said that most data refers to 10-year-old wells
that had been developed at the beginning of the shale boom, thus presenting fewer stage and a more
imprecise fracturing process.
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Figure 4.18 – Shale gas well production profile, Haynesville Shale Louisiana (Chesapeake energy)
Another issue that is currently being discussed is the so-called “re-frack”, the second hydraulic
stimulation of shale well that exhibits sub economic production. Some researcher claim that a second
stimulation process performed in non-stimulated portion of the formation could boost the production.
At the state of the art, these analyses are mainly speculative and not supported by sufficient field data.
In any case, despite all the improvements made in the drilling and stimulation process the
formation complexity, and lower reservoir quality results in a lower production with respect to
conventional natural gas wells. Because of the lower productivity and quicker decline rate shale gas
exploitation requires repetitive drilling, fracking and producing operations on a high number of wells
to sustain its production thus being much more intensive then production from conventional fields.
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Chapter 5
Global impact of the US Energy Revolution
The unexpected surge in the US gas production and the associated price slump on the domestic
market had a major effect on the economy. Due to the rapidity with which this production increase
took place and its effects, some analyst defined it “shale gale” or “new energy bonanza”.
It is indisputable that shale gas extraction has been a game changer in the US; at the beginning of
the millennia, US were experiencing an increasing dependence in foreign imports and their highest
natural gas price, higher than European ones in the same period (1999-2005). The shale gas boom led
to a gas oversupply and a quick fall of natural gas price. The economic impact has been vast ad
variable: increase in national employment in the oil&gas and service industry, higher federal incomes
through taxes and royalties and a sharp decrease in energy price that benefitted industrial and
residential customers.
Moreover, at the beginning of the millennium the US were forecasted in becoming the first LNG
importing country worldwide and, on the eastern cost, several project were developed. The shale
boom, however, completely reversed this prospective; from the next biggest importer the US became
a potential next exporter of LNG. The direct impact of the shale boom on the other regional gas market
came in the form of LNG cargos redirection. Many of LNG producing counties expand their
liquefaction capacity to gain share in the fore coming US market. The sudden price slump on the US
domestic market made imported LNG more expensive than domestic produced gas and so exporters
had to redirect their cargos to other markets.
Most of this LNG ended in the European market sold with flexible contract formulation and a
lower price with respect to piped gas. Traditional importers, in response to the reduction in their
revenues, started renegotiating contracts with their supplier demanding more flexibility and a less
strict oil-linkage. This shift from rigid and fixed contract towards a more flexible market could became
the first step into a radical change with the creation of a global gas market or, at least, a global
benchmark for gas price.
However, despite all the positive effect that the shale boom had in the US there is a wide opposition
to shale gas exploitation mostly because of the environmental impact of the hydraulic stimulation or,
as opponents call it, fracking. opposition quickly spread in Europe and “anti-fracking” called for a Eu
ban, de facto preventing the creation of an unconventional gas industry. The response of the European
member countries differed: France completely ban hydraulic fracturing process while Poland issued
permit incentivizing companies to explore Polish shale potential. Most of the other member states
issued a temporary moratorium on all shale-related activities waiting to develop some further analysis
and more accurate studies on the environmental impact.
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5.2. The Shale Gas Revolution
The United States have historically been the main oil and gas producing and consuming country
worldwide. Since the end of WWII oil consumption increased on a higher rate than domestic
production and the US began importing from Middle Eastern countries. The oil crises of the seventies
and the internal decline pushed the federal government in trying to reduce oil dependence employing,
wherever was possible, natural gas as a substitute. However, because the main source of US natural
gas is associated gas, gas production showed a similar behavior and domestic gas production began a
slow decline. The new project in Alaska and in the Gulf of Mexico were able to compensate the
depletion of the onshore gas field but it was not sufficient to cover the increasing gas demand.
Production decline and increasing consumption rose the import dependence and, at the beginning of
the new millennium, the United States were forecast to become the first importer of liquefied natural
gas; as a consequence, the construction of several regasification terminal was initiated in order to
import gas from exporting country in the Atlantic basin.
The shale gas revolution completely reversed this scenario: production from shale formation
increased 16-fold in a decade (2004 - 2014) providing the largest share of production, higher than
conventional and making the US almost self-sufficient. Despite the short lifetime of shale wells
improvements made on the extraction technologies and a better understating of reservoir behavior
raised the average EUR and, as a consequence, national production. The surge in the quantity of gas
domestically produced create an internal oversupply making price collapse; the spot price on the
Henry Hub reached a yearly average price of 2.75 $/MBTU, prices not seen since the end of the
nineties.
Figure 5.1 – Monthly natural gas production and henry Hub spot price (US Energy Information Administration)
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The first development of shale resources happened in the early eighties as a part of a research and
development program funded by the US government (Eastern Gas Shales Project). The first shale gas
wells were vertical well drilled in the Antrim shale, a relatively shallow shale formation (between
3800 and 800 m) in the state of Michigan. During the 1990s, the Antrim became the most active play
in the US, with thousands of wells drilled; at the end of 2010 roughly nine thousand wells had been
drilled and fracturated in this basin. The production from early shale wells was too low to be
commercially valuable without a federal tax credit exemption.
The shale development started in the Antrim basin but the real revolution took place in the Barnett
shale, a formation lying below the Dallas- Fort Worth metropolitan area in Texas. This shale formation
was known as the seal rock of the small conventional gas field located in that area, one of the most
productive of Texas. Because of its role as seal-rock several core taken from Barnett shale had been
extracted and analyzed to improve the drilling process leading to a good knowledge of the geology
and characteristics of the formation. The risk associated with early exploitation of shale gas in the
Barnett was mitigate by the presence of conventional gas pocket lying below the shale: whenever the
fracturated shale well would not result commercially exploitable, operators could drill through the
shale rock targeting conventional deposit.
The most active company in the Barnett was Mitchell Energy Corporation and Development
named after his founder George Phydias Mitchell, unanimously consider the father of the hydraulic
fracturing process and, in extension, of the shale boom the United States are living. Despite the poor
results given by the first wells drilled, Mitchell was convinced of the Barnett potential and kept trying
in order to find the perfect stimulation process. In 15 years, thanks to the funding of the unconventional
R&D federal programs, nearly 250 wells were stimulated with different technology, mostly foam or
gel based fracturing fluids.
The breakthrough came in 1997 with the very first massive slick-water fracturing treatment;
replacing foam or polymeric-based gel with water and reducing the quantity of proppant and chemical
additives stimulation costs were halved and the gas flow rate was nearly five time higher than
previously stimulated wells (Gold R., 2014). The success of Mitchell Energy encourage other
company in joining the shale gas business and the development rate of the Barnett shale escalated as
more and more operators leased prospective acreage and drilled toward the gas-bearing formation.
What happened in the Barnett was a real “shale rush”; the sudden discover of a profitable business led
operators in drilling as many wells they could as fast as possible.
The early development was based on trial and errors approach: operators were following a
“learning by doing” principle drilling the maximum number of wells in order to produce enough gas
to cover losses from dry wells (well with such low production that would be economical). A USGS
survey made in 2010 showed that on nearly ten thousand wells drilled between 1998 and 2010 slightly
less than half were producing gas and less than a third were commercially valuable. The majority of
shale wells were either not producing o not producing enough to recover their costs; the remaining
wells were producing enough gas to recover the losses of the others.
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Since the behavior of shale formation and stimulation techniques were poorly understood, the
difference between a dry or a highly productive wells was a matter of luck. The position of the wells
were related to above-ground factors (such as road access and the proximity to rivers or lakes) rather
than on scientific evidences of the reservoir quality in that area. Because of the extreme heterogeneity
of shale formation wells placed few kilometers away could exhibits tremendous difference in their
production rate.
Therefore, not all the company active in the Barnett shale basin profited; however, the ones that
succeeded began looking for other shale plays in the US. Within few year other shale gas basin were
identified and target for extraction. The first targets were basin located in proximity of the Barnett:
the Fayetteville shale (Arkansas), the Haynesville (Texas and Louisiana) and Eagle Ford (southern
Texas). Later on, other major play in the rest of the US were identified and developed; among those
new play there is the Marcellus shale, one of the world largest shale basin that stretch from New York
State to Pennsylvania and West Virginia. Production from this basin is currently accounting for the
40% of the overall US shale gas production, four time as much than the other two major play (Eagle
Ford and Barnett shale).
Figure 5.2 – U.S. dry shale gas production per basin (EIA)
The vast production of natural gas from shale formation had a major impact on the US domestic
economies, increasing employment and decreasing cost of natural gas for industrial, residential
customers user and, even more important, power plants owners. This price reduction increased the
competitiveness of natural gas-fired power against coal ones. In 2009 the average yearly price for
natural gas at the Henry Hub was 3.89 $/MMBtu compared with 2.45 $/MMBtu of hard coal. The
price gap was further reduced by the higher efficiency of CCGT power plant (an average of 42.6%
compared with the 33.7% of coal fired ones) that brought cost of producing a single Megawatthour
with gas to 31 $ slightly higher than the 25$ required with coal fired power plants.
The employment of a least carbon-intensive fossil fuel great environmental benefits reducing not
only carbon dioxide emission but also the emission of more hazardous pollutant such as hydrogen
sulphide, particulate matters and mercury. According to the IEA estimates, combustion-related carbon
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dioxide emission in the US have been constantly reducing from 2008: at the end of 2013, annual
emission reached the same level of 1996. The US has been the only country worldwide to experience
such an extraordinary decrease in their CO2 emission associated with an economic growth. European
emission shows a similar reduction but, contrary to the US one, this reduce emission is related mostly
to a general decrease in energy production on the wake of 2009 economic crises.
Figure 4.22 illustrate this shift from coal to natural gas and emission decline associated. From
2008 onwards, electricity production from coal power plant show a sharp decline, which caused a
strong reduction in the emission of CO2, equivalent to 750 million tons, equivalent to the 13% of what
produced in 2008; with this reduction the US reached the emission level of 1996.
Figure 5.3 – US electricity production per source and CO2 associated emission (EIA online dataset)
The rapid growth in shale gas production is also having an enormous impact on the national
economy: a report commissioned to HIS by the federal government suggest that that the shale gas
industry supported more than 600’000 jobs in 2012. It has been estimate that the “employment
multiplier” of the shale industry, is between 3 and 4, higher than the financial or construction
industries. In 2010 shale gas contribution to the American gross domestic product (GDP) was more
than $76.9 billion in 2010 and it is expected to triple to $231.1 billion in 2035. Beside the savings
some private owner are perceiving substantial lease from the oil&gas company plus the 13% of the
monthly market price of extracted oil and gas as royalties. Cheap natural gas is also revitalizing the
chemical industry that now has a price advantages in employing natural gas or associated liquid as
base feedstock instead of oil. For example, ethylene, an organic compound with extensive applications
in the chemical industry, can be manufactured from ethane (a NGLs) or from oil-based naphtha. US
chemical industries employ ethane whereas international competitors rely on a more expensive oil-
based raw material. The lower price of natural gas compared to oil results in a net economic which is
increasing the competitiveness of American chemical industries.
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5.3. Impact on the global LNG market and on European gas pricing
As described in chapter 3 Liquefied Natural Gas (LNG) is simply methane that has undergone a
cooling process until its liquefaction temperature (-162°C, at ambient pressure); in liquid state it
occupies a fraction of its gaseous volume (1/600th) allowing transportation by ship. However, natural
gas liquefaction is a highly energy-intensive process and accounts roughly for the 70-85% of the
transportation costs. Due to its high costs, LNG was chosen over piped gas only in cases where
connection with pipeline was not feasible, as in the case of South-Asian countries and Japan. Because
the main cost in LNG shipping is the gas liquefaction, LNG final price is practically independent on
the distance to be covered allowing operators to redirect their cargos to the most profitable market
without any sensible cost increase. To cope with the increasing concurrence, operators had to switch
to more flexible contract in order to keep their market share moving to a shorter contractual horizon
and increasing the share of LNG sold on a spot base.
However, what really changed the LNG market was the US shale revolution. At the beginning of
the new millennium, the increasing gap between domestic supply and demand was foreshadowing a
future as a net importing country. Because the amount of importable gas from Canada and Mexico
appeared not sufficient to keep up with the internal demand, massive investment in LNG receiving
terminals were made. Considering both new projects and expansions in 2013 in the US eleven
regasification terminals with a total capacity of 185.8 bcm/year (25% of the overall yearly gas
consumption) were present. However, the increase in shale production and the sharp decrease in
domestic price left no share for imported LNG. All the operator that expanded their liquefaction
capacity to supply the US had to find other markets to recover the huge investment made for these
plants and turned to the European market.
To penetrate into a market dominated by a rigid contract scheme LNG operators had to switch to
shorter and more flexible contract, selling LNG on a spot base pricing it according to the future gas
price on the NBP37. The lower price of LNG and the reduction of European consumption reduced the
amount piped gas sold by the traditional operators, which had to renegotiate their contracts with the
supplying countries.
The two graph below shows the existing connection between European gas prices and the
increment of LNG import. First graph represent the historical trend of NBP spot prices, average import
price in continental Europe and Brent crude oil, which is the benchmark for the oil-linkage in
European gas contracts. Second graph represent the total quantity of LNG imported in Europe
separated by importing countries. It is evident that the total quantity imported increased slowly for a
decade until a spike in the period 2009-2011 after which declined to historical level. The sudden
increase in LNG imports, particularly the English one, could be explained with the price historical
trend. The three prices have been always moving together; since 2006, however, this correlation
started to weaken due to an increase volatility of the NBP. For the period 2009-2011 NBP price was
37 NBP or National Balancing Point is the virtual trading market for the UK, the English equivalent of the Henry Hub.
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well below the average European import one; the lower prices made LNG more convenient than piped
gas thus explaining the increased amount of LNG imports. Its convenience with respect to pipeline
gas increased the overall amount of volume exchanged reducing the market share of the traditional
importers.
Figure 5.4 – a) European oil and gas price b) European import of LNG (World Bank dataset, Eurogas)
The combined effect of aggressive business strategy from LNG importers, its relative price
convenience and the European consumption decrease had a significant impact on the revenue of the
traditional importers. The reduction in their market share made them start questioning the long-term
oil-linked pricing mechanism adopted by traditional exporters. The contract review led to an increase
flexibility in both pricing mechanism and volume sold, which could be seen in the progressive
separation between Brent and gas price after 2011. The variation in contract formulation decreased
the attractiveness of LNG cargos reducing LNG imports towards European imports. This price
competition, although lasted for a very brief time, had the merit of showing the unnecessary rigidity
linked to the traditional pricing system and allowed their revision improving the role of European gas
hubs and increasing competition, essential to achieve a competitive and liberalize gas market.
5.4. Shale Gas in Europe
Europe is estimate having a significant amount of shale gas in pace; latest analysis (Eia & Ari,
2013) estimate a total quantity of risked gas in place of 138.6 trillion cubic meter (13.7% of the
worldwide RGIP). Technically recoverable resource are only the 18% of the one in place, equivalent
to 25 tcm (11.3% of the worldwide estimates TRR). In their report, Eia & Ari identified 13 prospective
shale gas basin stretching over 10 different countries. The most prospective basin identified are the
Baltic basin in Poland (2.97 tcm), the Paris basin in northern France (3.65 tcm) and the Northern and
Southern Petroleum System in the UK (1.3 tcm). Other shale play with lower estimate resources or
higher geological complexity are: the Alum shale in Denmark and Sweden (1.2 tcm), the Lower
Saxony basin in Germany (0.48 tcm), the Moesian Platform on the border between Romania and
Bulgaria (1.3 tcm) and the Cantabrian basin in Spain (0.22 tcm).
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Figure 5.5 – European shale gas basin with resource estimate (Eia & Ari, 2013)
As mentioned in the previous chapter assessing the quality of the shale rocks and its commercial
viability it is a complex operation; several different parameters are required to estimate the quantity
of gas in place and the structure of the deposit. Main characteristics for a shale gas basin to be
successful for commercial exploitation are: quality of the source rock, physical extent of the basin and
completion quality.
Quality of the source rock: determines the generation potential of the rock. Depends on the
deposition environment (kerogene type), the total organic carbon (TOC, wt %) and the thermal
maturity (Ro %).
Physical Extent of the basin: quantifies the amount of gas resource in place: it is simply the total
prospective volume (prospective area multiplied organic rich thickness)
Completion quality: describes the effectiveness of the fracturing process; it involves basin depth,
reservoir pressure, mineralogy, presence of natural fault system, amount of clay and geological
complexity (presence of fault or intense folding)
A commercial exploitable basin has a high areal extent and thickness, high TOC, low amount of
clay, a natural occurring faults system and a simple geological structure. Since in several European
shale basin no exploratory wells have been drilled to date, estimation of reservoir properties have been
performed with old logs or trough extrapolations of geological data from other sources. The lack of
reliable information and the low number of data present generates a high uncertainty in the final
estimation. To account for this uncertainty two factor are include into the evaluation of the risked gas
in place.
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Play Success Probability Factor (Play Factor)
This factor describes the likelihood that at least some portion of the basin will provide oil and/or gas
at attractive flow rates. Shale formations that are already under development would have a play
probability factor of 100% while formation with very limited amount of data could have a play factor
as low as 40%.
Prospective Area Success Risk Factor (Risk Factor)
This factor combines data uncertainty that could relegate a portion of the prospective area to be
unsuccessful or unproductive for shale gas and shale oil production. These concerns include high
structural complexity (e.g., deep faults, upthrust fault blocks), low thermal maturity (Ro between 0.7%
to 0.8%) or low net organic thickness. Since shale exploration always involves a certain risk, even in
the most developed basin of the US, the value is always lower than the unity going from 75% for
Canadians to 30% of basin with very limited geological information available.
In Europe these factor varies widely: the Baltic basin in Poland is experiencing first development
(although not in commercial quantity) and thus has a play factor of 100%, while the Moesian Platform
(in Romania) only 55%. Regarding the availability and the quality of the information presents the risk
factor varies between a maximum of 60% for Lower-Saxony basin (northern Germany) to a minimum
of 18% for the Southeast basin (southern France). As exploration proceed, and more information on
the play would be available, the value of both factor will change. It has to be said, although, that the
combination of those two factors do not represent the probability of play development, they rather
reflect the uncertainty and are used to correct the early estimation of the Original Gas in Place (OGIP).
Furthermore, after the correction with the composite factor the risked gas in place (RGIP) is
further reduced according to the recovery factor (an average value extrapolated from US experience
that range from 25% to 15% depending on geological conditions) to obtain the technically recoverable
resources (TRR).
5.4.1. Shale gas basin characterization
What is define as shale basin is the prospective area of much larger sedimentary basin formed by
the progressive deposition of sediments in lacustrine or marine environment. The shale basins
identified in Europe are part of three larger geological formation: one comprehending the four Polish
basins in Poland and the Alum shale (Sweden and Denmark), the second covers the area of Uk,
Northern France, Belgium, Netherlands, and Germany while the last one comprehends the northern
part of Spain and the southern of France. The main characteristics of European shale, when compared
to North American ones, is their older geological age, greeter depth, higher pressure and temperature
and higher clay content. Because of the greater depth, European shale basin experienced higher
temperature and the prospective area for oil is much lower than the one for dry gas.
In Eastern Europe, four out of the five prospective basin are located in Poland; the largest one
(Baltic Basin) stretches across the country and it is estimated containing significant amount of gas. Its
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thermal maturity varies in a wide range (0.85 – 1.8% Ro) thus being prospective not only for dry gas
(67% of the basin) but also for natural gas liquids (24%) and, to a lesser extent, oil (9%).
The only Eastern shale basin outside Poland is the Moesian Platform is located on the border
between Romania and Bulgaria. In this case the largest part of the basin (92%) is prospective for wet
gas, while dry gas prospective is the remaining portion.
Table 5.1 – Eastern Europe prospective shale basin
Country Basin Area
(Km2) Thickness (m) Depth (m)
Average
TOC (%wt)
Thermal
Maturity
(% Ro)
Play
Factor
Risk
Factor
Risked Trr
(bcm)
Poland Baltic Basin 22'200 138 2'000-4'900 3.9% 0.85-1.8% 100% 40% 2'970
Lublin 6'190 70 2'130-4'900 3.0% 1.35% 60% 35% 260
Podlasie 7'670 90 1'800-4'900 3.0% 0.85-1.8% 60% 40% 280
Fore Sudetic 23'490 56 2'440-4'900 3.0% 1.60% 50% 35% 600
Romania
and
Bulgaria
Moesian
Platform 24'710 138 1'500-5'000 3.0% 1.15-2% 55% 40% 1'320
Despite the greater number, Western Europe shale basin are, on average, less prospective than
Eastern ones. These basins tend to be shallower, with lower organic-rich volume, lower TOC and
holds less amount of risked technically recoverable gas. Two exception are the Alum shale and the
Paris basin; the first one, despite the high TOC and the areal extent, has low play and risk factor that
express its geological complexity. The Paris basin, it is by far the largest in Europe and has the largest
resource of estimated technically recoverable gas and mostly, it seemed to be subdivided equally
(roughly one third each) between oil and associated gas, wet gas and dry gas.
Table 5.2 – Western Europe prospective shale basin
Country Basin
Area
(Km2) Thickness (m) Depth (m)
Average
TOC (%wt)
Thermal
Maturity
(% Ro)
Play
Factor
Risk
Factor
Risked Trr
(bcm)
Denmark
and
Sweden
Alum Shale 20'980 61 1'000-3'970 7.5% 2.00% 60% 50% 1'200
France Paris Basin 138'600 35 1'200-4'900 9.0% 0.85-1.6 % 90% 60% 3'650
Southeast
Basin 9'790 48 2'500-5'000 2.0% 1.50% 60% 30% 200
Germany Lower Saxony 11'580 27.5 1'000-5'000 8.0% 0.85-2.0 % 100% 60% 500
Netherland
West
Netherland
Basin
14'660 74 1'000-5'000 4.2% 0.85-1.2 % 75% 60% 750
Spain Cantabrian 5'440 46 2'440-4'420 3.0% 1.15% 80% 50% 240
UK North
Carboniferous 13'210 125 1'520-4'420 3.0% 1.30% 60% 45% 710
South Jurassic 4'490 46 1'220-1'830 3.0% 0.85% 80% 50% 12
Shale basin in Europe are promising but, contrary to the US, Europe has a higher population
density and a vast portion of its territory is considered environmental protected area cover Natura
2000 regulation.
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In these areas intensive and industrial activities, as shale-gas exploration and extraction, would be
limited if not prohibited. In order to estimate the remaining shale gas potential available for each of
the prospective basin, the portion of off-limit land should be considered and the available resource re-
estimated. This would be a very complex and site-specific analysis requiring a specific knowledge of
the gas resource present for each portion of the basin. A first rough estimation has been performed
and summarize in the following table.
Table 5.3 – Comparison of Eu-28 shale gas estimates with conventional reserves
Eu – 28 Member State
Source (min/Max) % of Off-Limit
Land Min / Max TRR
(bcm)
Conventional Reserve
(bcm)
Austria Thompson Reutes 2012 27% 116.6 - 176.8 8.5 Bulgaria Bloomberg 2012 / Eia&Ari 2013 39% 182.5 - 292.7 5.7 Denmark ICF Consulting 2014 / Eia&Ari 2013 22% 178 - 710 34.3 Estonia ICF Consulting 2014 / Eia&Ari 2013 24% 2.3 - 13 0 France ICF Consulting 2014 / Eia&Ari 2013 27% 704.5 - 2'817.5 9 Germany BGR 2012 / Eia&Ari 2013 50% 240.3 - 340 97 Hungary Veliciu and Al. 2013 / Eia&Ari 2013 32% 269.7 - 676 7.8 Ireland Energy Oil 2013 18% 34.4 - 89 10 Latvia ICF Consulting 2014 / Eia&Ari 2013 16% 3.4 - 21 0 Netherlands Eia&Ari 2013 78% 108 - 165 898 Poland PGI 2012* / Eia&Ari 2013 32% 702.8 - 2'837.4 85 Romania Veliciu and Al. 2013 26% 171 - 1'067 105
Spain Eia&Ari 2013 38% / - 140.2 2.5
Sweden ICF Consulting 2014 / Eia&Ari 2013 20% 57 - 227 0
UK UK DEEC** 2012 / Eia&Ari 2013 53% 268 - 350 240.7
* Polish Geological Institute ** Department of Energy & Climate Change
Different authors shale gas estimates have a wide variability due to the uncertainty involved in the
basic hypothesis, the lack of production data and the difference in the evaluation methodology chosen.
In the table the latest estimation performed are presented: values for “minimum recoverable shale gas”
are taken from the lowest estimation present in literature while “maximum recoverable shale gas” is
taken, when present, from the Eia & Ari report of 2013. Estimates higher than Eia & Ari ones have
not been considered; this choice has been made in order to be conservative regarding European shale
gas potential.
Population density and Natura 2000 sites are considered to determine the off-limit potion of land.
The area covered by Natura 2000 is expressed as a percentage of the total land and it consider as off-
limit. To assess the percentage of off-limit area due to population density the average density per
square kilometers of each country have been considered and the off-limit portion assess (from 95% in
case of more than 350 people per square kilometer to the 5% in case of less than 100). The portion of
off-limit area is used to lower both minimum and maximum shale gas estimates.
This procedure is, of course, very rough; a proper estimate would consider each prospective basin
evaluating how much of the prospective area is protected or lies beneath a populated area. Despite the
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crude methodology is evident that, even considering the lower estimates, the estimate technically
recoverable shale gas sources are three times bigger than conventional ones.
Comparing shale gas resource with conventional reserves could be misleading. They indicate two
typology of gas resources: reserves considers also the commercial feasibility of the gas extraction
while TRR evaluate only the technological feasibility of its extraction regardless of extraction costs
and natural gas price. European unconventional gas industry is still in its infancy and, because no
country passed the exploratory phase, the commercial viability of these projects is still a major issue.
Further investigation would be necessary to understand shale gas potential.
5.4.2. Exploration activities in Europe
The potentially large unconventional shale gas reserves in Europe had stimulate the industry
interest and since 2008, several European and international company acquired permits and exploratory
license to assess the European potential. Around fifty companies are involved in exploration activities,
and the whole spectrum of the industry is represented. Five are Majors (ExxonMobil, Shell, Total,
ConocoPhillips and Chevron), four are large caps (Marathon, Nexen, Talisman and BG (via QGC)),
three are National Oil Companies (PGNiG, OMV, and MOL) and two are European utilities
(GdFSuez, RWE). The largest amount of this exploratory license has been leeside in just two country:
France and Poland. Since 2010 exploratory concession have been released in in the UK, Poland,
Germany, Romania, Denmark and Hungary; to date, only in Poland and the UK shale wells have been
fracturated to assess the quantity of recoverable gas.
However, in many European country license were withdrawn and shale gas exploration put on
hold because of environmental concerns related to the process of hydraulic fracturing. In the United
States, despite the economic benefit resulting from shale gas exploitation, environmental activist
started protesting against it. This protest increased after the release, in 2010, of the movie “Gasland”,
a documentary showing the impact of the shale development on the rural community of the United
States. The main claim of the “documentary” is that the process required to fracturated the shale
formation, hydraulic fracturing, was employing toxic and cancerogenous additives that were leaking
into groundwater contaminating it and increasing health diseases for the communities where shale gas
exploration was taking place. Despite having been defined “wildly inaccurate and irresponsible” by
members of the Environmental Protective Agency, Gasland obtained an incredible success
contributing to support the claim of the “anti-fracking” movement.
The shale opposition became particularly strong in Europe and, in response to that, several
countries banned hydraulic fracturing or put a moratorium. Since in the European Union no common
legislative frame regarding hydrocarbons exploitation exist, decision whether or not explore for shale
gas is left to national governments. Government’s position varies greatly across the Union: after
massive protest, France and Bulgaria banned hydraulic fracturing pushing for an extension of this ban
everywhere else in Europe. Some other government proceeded with more cautiousness: in the UK, a
temporary moratorium was set in place after the first stimulation process triggered a series of small
seismic event. Despite the relatively low magnitude of the earthquakes generated (largest one was
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measuring 2.5 on the Richter scale) and the absence of surface damage, government interrupt shale
testing in order to determine the causes of this earthquakes and develop mitigation rules. Following
this accident, the Royal Society and Royal Academy of Engineering began an extensive review of the
existing studies in order to assess the environmental and human health impact of hydraulic fracturing.
A similar moratoria is in place in Germany were the release of permits for hydraulic fracturing is a
halt until “concrete evidence has been put forward to prove that the process is safe in regards to its
impact on health and the environment”. Due to the ban or the moratoria pending on the process of
hydraulic fracturing the European shale gas exploration was substantially put on halt.
Figure 5.6 – European regulation regarding shale gas exploration and hydraulic fracturing (The Economist, 2012)
To date just a bunch of wells have been drilled and no hydraulic stimulation has been carried out
outside of Poland. In fact, Poland is the only member state were the majority of the public is in favor
of shale gas exploration; despite environmental worries shale gas is considered the only solution to
achieve a substantial energy independence from Russian gas.
The large and continuing uncertainty in shale gas resource estimates has important implications
for the future of the shale gas industry and national energy policy. Even in areas where exploratory
wells have been drilled (to date only Poland and the UK) significant uncertainty remains. Initial
exploration has confirmed the presence of significant potential. However, reservoir characteristics are
more challenging than originally expected leaving a significant uncertainty on the commercial
viability of shale gas projects.
Across Europe the local structural geology of shale basin is poorly known; this increases
uncertainty and risks related with the concession lease because of eventual faults, which may interfere
with shale drilling and completion. According to the US experienced derisking shale plays typically
requires drilling about 100 wells, while achieving economies of scale requires many hundreds more.
Consequently, considerable exploration drilling and seismic surveys are still needed to define
European locate sweet spots, and several hydraulic stimulation will be needed to understand the
behavior and the response of European formation.
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5.5. Environmental Impact of shale gas recovery
The worldwide environmental opposition to shale gas extraction, called anti-fracking movement,
gain strength after a defamatory media-campaign started in the USA. General and non-specific media
contributed in popularize alarming reports or frightening documentaries regarding shale gas related
activities. Rather than inform and discuss the topic on a scientific basis they rely on the emotional
response of the viewer when shown disquieting images of weird diseases, massive water or soil
contamination or outlandish phenomena linking them to hydraulic fracturing operation in the area.
However, most of the footage shown have nothing to do with hydraulic fracturing; for example a clip
from the movie “Gasland” shows a man that light his tap water on fire “because of the leakages of
methane and flammable fracturing fluid” (figure 5.6a). This clip soon become viral on YouTube and
alimented the environmental opposition; despite being surely shocking, water catching fire due to the
quantity of methane present is not a new phenomenon. Similar cases have been reported since the XIX
century as a consequence of the infiltration of methane into water stream from deposit of swamp gas
(shallow biogenic methane) or gas seepage on the surface. Unfortunately, due to the high emotional
impact media coverage tend to give more space to this type of material rather than well documented
study, report or scientific articles.
This king of media coverage material created some important drawbacks in the national acceptance
of shale gas exploration. Along with energy prices and technological advancement, public attitudes
will play a critical role in the development of unconventional reserves. Therefore, a correct
information regarding the process of unconventional gas extraction and exploration would be essential
to gain the favor of the local community. This acceptance would be particularly important in Europe
because of the absence of a financial incentive or compensation for local community living nearby
shale exploration.
Figure 5.7 – a) The “water tap on fire” clip from Gasland
b) Tone of media coverage of shale gas development in the USA (Wang et al., 2014)
One of the most misleading affirmation made by anti-fracking activist is that fracturing process is
a relatively new technology and, for this reason, still poorly understood, this claim is obviously false.
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Slick-water fracturing (the water based hydraulic fracturing system employed nowadays) was
developed in 1997; however, reservoir stimulation process date back to the beginning of the oil
industry. First stimulation process was patent in 1866 (only eight years after the first oil well) and
employed a torpedo (a canister filled with gunpowder or nitroglycerin) that was ignited at the bottom
of a well to remove residues increasing flow rate. After torpedoes, next step came in the thirties when
reservoir began to be stimulated with acid to dissolve the limestone rock surrounding the well. The
very first process of “hydrofrac treatment” was performed in 1946 and employed thickened gasoline;
well flow rate did not increase as expected and the test was considered a failure. However, industry
interest for this technique increased and soon investigation on the fluid typology, fracture propagation
and self-closure begun. The first hydraulic proppant fracturing was carried out in 1952 in the Soviet
Union, and soon this process became a standard operation. In Europe, more than 500 conventional
wells have been hydraulically stimulated since the seventies without any reported accident. In the end,
the water-based fracture of shale formation is rather new but, contrary to what anti-fracking protestor
claim, the process itself is part of the industry common practice.
5.5.1. Impact on water resources
Anti-fracking activist claim that employs vast amount of toxic or carcinogen chemicals without
any regulation or supervision, which ends up polluting the water table and creating serious health
hazard. This widespread concern are motivated by a partial knowledge of the hydraulic fracturing
process. According to a survey performed in the USA (Boudet et al., 2014) the vast majority of people
interviewed believed that the amount of water that was not flowing back to surface was leaking into
the surrounding rock layer seeping into aquifers. As explained in chapter 4, injected water is partially
retained by shale formation because of its unsaturation condition and the capillary forces acting within
the nearly created fractures.
The chemicals employed are less than 1% per volume and for each fracturing job the exact
composition of the fracturing fluid is described into the environmental impact assessment and has to
be presented to state regulators to be evaluate before fracturing process could begin. Moreover, most
of the chemical additives employed in Europe are employed in the food processing and pharmaceutical
industry. In Europe, all chemicals that would be employed would have to present an extremely low
(when none) toxicity and no potential health related hazard; all chemicals have to be listed and
approved by the REACH38 regulation.
Another erroneous belief, always according to Boudet’s survey, is that the artificial fractures could
create a pathway between shale formation and aquifer enabling fracturing fluid and hydrocarbons to
flow into groundwater. This is an impossible event: on average the most prospective part of the
formation are located between 2’000 and 4’000 meter below surface while potable water aquifer rarely
38 REACH is the Regulation on Registration, Evaluation, Authorization and Restriction of Chemicals; in force from 2007 represents the legislative framework on chemicals of the European Union (EU).
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are deeper than 250 meter. To convince the public of the process safety, Halliburton (one of the major
oil service company worldwide) commission a study to assess the maximum extension of fracture
above shale formation. The studies analyzed a wide range of shale wells drilled and fracturated by
different companies in the Barnett since 2001 and in the Marcellus since 2008. Results for the Barnett
are shown in figure 5.7. For each of the 10’000 wells surveyed both minimum fracturing-cluster depth,
fracture dimension (both height and depth) and maximum depth of the groundwater aquifer in the area
are illustrated. In association with the wells dimension the maximum depth of the aquifer present in
area is report. This operation has been repeated for several portion of the Barnett located in different
State County. The red-colored band illustrates perforation depths for each stage, with the mapped
fracture tops and bottoms illustrated by colored curves corresponding to the counties where they took
place. Statistically fracture depth (length below the perforating depth) tend to be longer than fracking
height (above perforating depth). As could be seen the distance between the highest fracture and the
deepest drinkable water source is about 3’000 feet, which is slightly less than 1 kilometer. Moreover,
this “low” distance is present only in one county (Archer) while all other cases the distance separating
fracture and aquifer are much higher.
Figure 5.8 – Marcellus Mapped Frac Treatment (Pinnacle, Halliburton)
Other studies address this problem; the largest research collected data of several thousand wells
from five shale plays in the US (Barnett, Eagle Ford, Marcellus, Niobrara and Woodford) and from
offshore conventional wells located in Norway, Mauritania and Namibia (Davies R.J. et al.).
According to their results, 80% of fractures in shale basins did not pass the height of 100 meter with
the only exception being the Marcellus where the 80% cumulative is found with length of 200 meter.
In any case, fractures have a probability lower than 1% to grow longer than 300 meter: the huge
distances separating the fracs from the nearest aquifers, demonstrating that hydraulic fractures can not
growing into groundwater supplies contaminating them.
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The vast concern arose and the high number complain regarding methane contamination of water
wells made the EPA creating an investigation Committee to assess the impact of shale gas related
operation on water sources. The results of the EPA four-year study were released in a final report in
January 2015: in none of the water wells, claimed to be contaminated by the shale gas extraction
process, any trace of chemicals being used in the fracturing fluid was found. However, cases of high
quantity of methane within the water wells were randomly found. The EPA performed an inspection
of the wells in the area nearby the two most contaminated site, the village of Dimock (Pennsylvania)
and Pavillion (Wyoming), and found that the well casing had been improperly cemented allowing
contamination to occur. The cementing job had been performed sub-optimal operation leaving a
partial void in the annulus39 trough which methane leaked. Despite not being toxic methane could built
up within wells and pipes creating potential explosive mixture, so methane leakage is an issue to be
address. The EPA sue the companies responsible that had to re-cement the well and pay an indemnity
to the residents.
The conclusion of the report was that the most possible way to contaminate groundwater is related
to the on surface handling of fracturing water and chemicals or wastewater rather than the fracturing
process itself. The surface spillage could be caused by problems in the surface piping, truck accident
or pit overflown while the direct contamination from the well would be possible only in case of
extremely poor cementation or if a blowout occurs during stimulation process. All events that could
be easily avoided by enforcing a stronger regulation and employing industrial best practices.
5.5.2. Hydraulic fracturing water cycle
A shale well requires, on average, approximately 1.5 million gallon (5.7 million L), which makes
up of the 90% of the fracturing fluid. This values are, however, extremely variable depending on well
length, formation geology, and fracturing fluid formulation: average water requirement pass from
more than 5 million gallon (19 million L) in Arkansas, Louisiana and West Virginia to less than 1
million gallon (3.8 million L) in California, New Mexico, and Utah. According to EPA’s estimate,
cumulatively hydraulic fracturing activities in the United States used on average 44 billion gallon of
water a year in 2012, less than the 1%.
Although yearly water consumption on a global level is almost negligible, water withdrawals could
potentially affect the quantity and quality of drinking water resources at more local scales. Each phase
of the “hydraulic fracturing water cycle” has to be analyze in order to identify the risks associated and
improve specific regulation. The phases in which life cycle is divided are: water acquisition, chemical
mixing, well injection, flowback and produced water, wastewater treatment and waste disposal.
39 The annulus of an oil well is any void between any piping, tubing or casing and the piping, tubing, or casing immediately
surrounding it.
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Figure 5.9 – Hydraulic fracturing water cycle (EPA, Final Report 2015)
Water Acquisition
Water comes from surface water, groundwater or wastewater from previous fracturing operations.
Source choice depends largely on water availability: in the eastern United States surface water is
employed, while in the semi-arid western states generally a mix of surface and ground water is chosen.
High water consumption alone does not necessarily result in impacts to drinking water resources;
rather, impacts result from the combination of high water consumption and low water availability at
local scales. To avoid a potential negative impact, operators should improve their water management,
increasing the fraction of recycled water, develop new methods to employ seawater or brine in order
to minimize freshwater withdrawn.
Chemical mixing
Storing, mixing, and pumping of chemicals and hydraulic fracturing fluids on drilling site could result
in accidental releases, such as spills or leaks. Potential impacts to drinking water resources depends
on the characteristics of the spill and the quantity of chemicals spilled. In its report, the EPA identified
151 on-site spill none of which reached groundwater or show any traces of contamination.
Well Injection
Major mechanism by which the injection of fluid and could lead to contamination of drinking water
resources is a leak from the production well. This could happen in case of inappropriately cemented
wells or if steel casing is inadequately design to withstand fracturing operation pressure. According
to EPA, main risk would be old and abandoned oil wells not properly plug. The stress induce during
fracturing operation might cause the failure of the old cement leading to the leakage of hydrocarbons
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in the surrounding rock strata. Many historically oil producing state created programs to identify
abandoned oil well in order to map and properly plug them.
Flowback and produced water
The amount of produced water returning to surface varies between 25% and 60% of injected volumes.
Total volume recovered depends upon the characteristic of the formation and the type of fracturing
process performed. Some exemption exists, such as the Barnett Shale, where the total volume of
produced water can equal or exceed the injected volume. Once water flows back on the surface it is
separate from the produced hydrocarbons and stored on site waiting to be treated. Between storing
system, the most common was the waste-pit; a pit dug close to the drilling site and cover with an
impermeable membrane. Despite being the most practical and inexpensive solution some case of
waste-pit failure have been detected: the improper impermeability of the layer lead to the leakage of
part of the fluid stored into surrounding ground or spillover caused by heavy rainfall events. In order
to avoid this potential contamination EPA suggest to employ steel tanks as storage medium.
Wastewater treatment and waste disposal
Hydraulic fracturing generates large volumes of produced water that requires management. There
essentially three type of wastewater managements: underground injection control (UIC) well disposal,
wastewater treatment and discharge at a centralized waste treatment (CWT) facility or on-site
recycling and reuse for further fracturing process. Wastewater management decisions are based on the
water availability and costs of disposal or treatment. The vast majority of wastewater produced by
industrial process (not only the oil and gas industry) is injected into disposal wells but injection wells
have limited storage capacities that would not be sufficient to dispose all the water coming from new
shale wells. Moreover, stress caused by the high quantity of pressurize fluid is demonstrate being
related to seismic event (see next chapter). Main risks related to disposal come from the treatment
process because EPA survey shown that some centralized waste treatment facilities (CWTs) in
Pennsylvania have been treating hydraulic fracturing wastewater without possessing equipment able
to handle the high salinity of the wastewater. EPA suggest enforcing stricter regulation on the process
required to handle those wastewater in municipal treatment plant and to increase the fraction of
recycled water.
5.5.3. Water consumption
A single shale wells consumes from 1 to 5 million water gallon per wells (4 – 18 million liters);
this seem a tremendous amount of water when compared to the individual but it ends up being rather
low compared to industrial applications or irrigation requirements. In the US the same amount of
water required to hydraulically fracture a shale wells is consumed in the irrigation of an average 18-
hole golf club for 3 to 5 weeks. In 2010 researcher from the Harvard University, conducted an
extensive review evaluating water employments of different energy resources. Water consumption for
shale gas was related operation resulted higher than conventional gas extraction but lower than all the
other energy forms surveyed.
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Table 5.4 – Water consumption during fuel extraction and processing
Water Consumption (gal/MMBtu)
min - (average) - MAX
Shale Gas Extraction 0.6 (1.4) 1.8
Natural Gas Processing and Transportation 0 (1) 2
Oil Extraction (Secondary Recovery ) 2 (45) 63
Oil Extraction (EOR or Tertiary Recovery ) 38 (65) 95
Crude Oil Refinery 7.2 (11) 13
Coal Mining 1 (2.7) 6
Coal Washing 0.3 (0.9) 2
Coal Transportation (Slurry Pipeline) 3.2 (5.2) 7.2
Uranium Mining 0.5 (3.8) 6
Uranium Enrichment 4 (6) 8
Conventional gas extraction is not included because water is employed only as part of the drilling
mud; set against the energy content of natural gas ultimately recovered from production well, the net
water intensity is effectively close to zero. Similar consideration could be made for oil extraction;
however, the high water intensity depends on secondary recovery and EOR40 .
Considering the total water consumption required to produce an unit of electric energy the
employment of natural gas (here considered as shale gas) in combination with GGCT results in the
lowest consumption of all power plant.
Figure 5.10 –Water consumption in electricity generation41 (Mielke E. et al , 2010)
40 Secondary recovery employs a process called water flooding; it employs auxiliary wells to inject water at the bottom
of the reservoir to raise the hydrostatic pressure of formation water and lift the oil. EOR (Enhanced Oil Recovery) instead, inject steam or a mixture of water and chemicals to fluidify the oil reducing its viscosity and, consequently, increasing extraction rate. According to a survey performed in 2009 by the U.S. geological survey, only 0.2% of the active oil well in the US employ primary recovery, the remaining employs secondary or advance recovery system (79.7% and 20.1%, respectively). 41 OT and CL stands, respectively, for Once Trough or Close Loop, two different system of power plant cooling
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5.5.4. Induced Seismicity
Induced seismicity is one of the major concern related to hydraulic fracturing process and, in
general, to all the oil and gas industry. On January 2011 in Oklahoma (USA), 43 low intensity quakes
(intensity ranging from 1 to 2.8 ML) were reported in the 24 hours following the hydraulic fracturing
of a shale well. The same years, on April 2011, a quake of 2.3 ML was detected shortly after Cuadrilla
Resources Ltd. fractured the first UK shale well in the Bowland Basin, north-west Lancashire. The
earthquake generate by the first fracturing job in the UK was followed by an excessive fears and
hysteria. In fact, the seismic event had a very low magnitude (2.3 ML) which is below the threshold
of potential damage. Vibrations from a seismic event of magnitude 2.5 ML are broadly equivalent to
the traffic, industrial and other noise experienced daily.
A 2013 paper written by Davies and al. reviewed the major studies present on induced seismicity
concluding that earthquake generation possibility of hydraulic stimulation is between the lowest. The
high-pressure fracture is a transient operation and, despite being able to open fissure within the rock,
it has an extremely low possibility of inducing a fault-slip. The stress required to cause a fault slip and
generate an earthquake would require the application of a constants stress for a longer period. The
only possible way hydraulic fracturing operation could cause an earthquake is the direct introduction
of fluid in the faulty plain, which would act as a lubricant lowering shear stress and causing the slip.
In conclusion hydraulic fracturing process has generated just two event of extremely low magnitude
when compared to other cause of anthropogenic seismicity.
Figure 5.11 – Frequency vs. magnitude for the review event of induced seismicity (Davies R., 2013)
Despite the low risk presented, hydraulic fracturing should not be performed in areas with
potentially active faults. As safety measure the process should include a smaller pre-injection and a
real time able to provide automatic locations and magnitudes of any seismic events generates halting
operation if events of magnitude 0.5 ML or above are detected.
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5.5.5. Land Consumption and Spatial Constraints
Together with the negative impact on the environment, European opponent claims that shale gas
extraction consumes a large amount of soil and it would be only possible in areas with extremely low
inhabitant density such rural area in the US countryside. Therefore, they claim, this type of operation
would be impossible in the much densely inhabited Europe. It is undoubtedly true that land
consumption of shale gas extraction is higher than conventional gas extraction and that Europe is more
densely populated than the US but none of this aspect seems a real obstacle.
First of all, the horizontal drilling techniques combined with multipad allowed the drainage of an
extensive portion of the reservoir from one drilling site minimizing the land footprint. For example, a
common well cluster configuration (as shown in figure 4.13) has 8 horizontal section; commonly each
section length is between 1.5 to 2 km long and the section are spaced between 250 and 350 meter one
another depending on fracture propagation. Drilling site occupies 3 to 5 acres (0.014 – 0.02 km²) while
the wells extent for 750 to 1’380 acres (3 – 5.6 km²) in the shale formation. Once drilling rig is moved
away and the fracturing fleet leave sites land is partially reclaimed leaving only the production
facilities which occupies from 0.2 to 0.5 acres (0.00081 – 0.002 km²), less than an operating
conventional field.
Regarding the US shale boom happening in the “almost inhabited countryside” the first basin that
has been exploited was the Barnett Shale, which lies beneath the fourth largest metropolitan area in
the U.S, and the largest in Texas (Fort Worth – Dallas metropolitan area). Despite the very high
density of the population in that area (706 people/km2), the play has been in a full scale development
phase since the early 2000s, with more than 1,000 natural gas wells already drilled as of December
2009, and in all types of zones, including residential ones such as the airport and even the university
campus.
Figure 5.11 – a) Map of Texas, population density b) Shale wells drilled in the area in 2010 (US BLM)
The conclusion of this analysis is that the presence of large urban areas is not an absolute physical
obstacle to shale gas related activities it only poses higher logistics problem and safety risks, both of
which could be easily managed.
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5.5.6. Greenhouse-gas Emission of Shale Gas Recovery
Methane is a very powerful greenhouse gas and possess a global warming potential 25 times higher
than carbon monoxide; therefore, any fugitive emissions during shale gas extraction could reduce the
benefits of its lower combustion emission. Possible emission during shale extraction process involves
leakage from pipes, pumps or other equipment and the practice of venting and flaring.
This topic became highly debated after Howarth and Ingraffena (2011) published a paper
concluding that shale gas produced at least 20% and perhaps >100% more emissions than coal on a
20-year time horizon. Several authors and academic researcher criticize this conclusion addressing
the very life-cycle estimated leakage in shale wells chosen (i.e. 3.6 – 7.9%) and the fact that methane
production generate during coal mining was not being considered. In order to verify this results
O’Sullivan and Patsev (2012) assessed fugitive methane emissions during flowback phase of nearly
four thousands horizontal wells. Their estimated CH4 emission before production were 1,678 billion
m3 or 902 kton (i.e. 228 ton per well or 0.4 – 1.0% of the well gas production over its lifetime). This
estimation were made considering all the methane release with the flowback water as vented while
this methane is capture of flared on site further reducing emission to 216 kton (i.e. 50 ton per well).
They concluded that such emissions are only slightly higher than emission from conventional wells
and are unable to alter the overall greenhouse gas footprint of the natural gas production sector, which
is dominate by the emission during the combustion process.
McKay et al. carried out the most recent analysis in 2013, as a part of the research willing to assess
the environment impact of shale gas extraction in the UK. Trough literature review and real data from
shale fields they performed an evaluation of the greenhouse gas impact of domestic shale: not only
domestic shale gas lifetime emission are sensibly lower than coal ones but also lower than gas
imported from extra Eu both trough pipeline or LNG. When referred to electricity production the
higher efficiency of gas-fired power plant determine even a bigger difference in emission between
coal and shale gas.
Figure 5.13 –Comparison of the life-cycle emission for the production of electricity (Mackay et al., 2013)
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Probably the biggest difference in terms of emission between conventional and shale gas
exploitation is related to the truck fleet required to carry all this equipment on the drilling site. Shale
gas wells have a lower life span than conventional one and, due to their faster depletion, a much higher
number are request to sustain gas production. The need of an intense drilling process lead to higher
emission because diesel engine used to power the drilling rig, the fracture equipment and the truck
fleet used to carry or remove equipment and fracturing fluids from drilling site. In order to reduce
this emission some operators in the US are experimenting the use of micro gas turbine to power rig
and electric equipment and dual-fuel engine (LNG and diesel) for their truck fleet.
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Chapter 6
The European way to shale gas
The US shale experience triggered significant interest within the European community. However,
despite the large economic impact shale gas remains a controversial topic and worries regarding the
environmental impact of the extraction process remains. If it is true that all oil and gas industry
operation tend to be seen with some suspect by the general public it has to be said that the drilling
insensitivity US makes public opposition even stronger. European response to the first exploratory
project differed across the Union; public opinion has to be taken in consideration because, together
with the specific characteristics of domestic energy market, is what shapes the energy policy adopted
by a government. Reactions ranged from a total ban of unconventional gas exploration activities to
the full government support. This two extremes situation represents the actual situation of France and
Poland; almost all other member countries adopted a “wait and see” approach waiting results of first
exploratory wells and the conclusions on the environmental impact.
Beside the public opinion what determined the choice whether or not to explore for shale gas was
the country dependency on natural gas and its share within the energy matrix.
In France, because of the reliance on nuclear power, the share of natural gas within the energy
matrix is relatively low; natural gas imports are equally subdivided between Norway, the Netherland,
Algeria, Russia and Qatar’ LNG. Worries related to energy security and uncertainty regarding gas
supply are not main worries in France; it is easy to understand the reason why environmental worries
overcame potential shale gas benefits. Opposite situation exists in Poland: natural gas is playing an
increasing role in the country energy mix for both the increasing industrial activities and the power
generation. To date, penetration of CCGT and natural gas-fired power plant is still very limited and
most of the electricity produced comes from coal power plants; any increase in the consumption of
natural gas would surely have tremendous environmental benefits. The polish problem with natural
gas is that Poland imports nearly all its consumed gas from Russia and any increase in gas
consumption will increase it dependency on foreign exports threatening country energy security.
Considered as a whole, the potential and challenges of an increase consumption of natural gas in
Poland could describe the European situation, when considered as a whole. There is huge potential
for natural gas consumption especially in the transportation and power generation sector; is undoubtful
that any substitution of coal or oil-based fuel with natural gas would results in an environmental
benefit and a reduction of greenhouse gas emission. However, any increase in natural gas consumption
would result in an increase in foreign imports thus increasing European energy dependency.
The aggressive energy policy operated by the Russian monopolist Gazprom and the instability in
the Middle East makes the high European dependency on imported gas a potential threat.
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6.1. The shale dream: the case of Poland
The only European country where shale exploration has been ongoing in Europe is Poland. The
first estimation of Poland shale gas, made in 2011, generate a vast amount of interest such that
European media (for example The Economist) described Poland as the “shale El Dorado” or “fracking
heaven”. Poland’s risked, technically recoverable shale resources are estimated at 4.5 trillion cubic
meter of gas and 1.8 billion barrels of oil in four basins. Initial exploration confirmed resource
potential but suggests that reservoir conditions are more challenging than originally anticipated.
Company found a more complex geology with respect to the US, a complex bureaucracy system and
higher costs related to the relative immaturity of unconventional industry in Europe. Despite the first
test well has been drilled nearly five years ago no commercial recovery scheme has emerged and
Poland’s shale industry is still at an early exploratory, pre-commercial phase.
In six years the 15 members of OPPPW (the consortium of national and major company created
to exploit Polish shale gas resource) drilled 64 shale wells (53 vertical and 11 horizontal) hydraulically
stimulating 22 of them (12 vertical and 10 horizontal). The initial results have been less successful
than hoped: production rates and reservoir quality have been lower than expected and hydraulic
fracturing operations have been sub-par. The main obstacles is the lack of reliable geological data that
makes operators uncertain about the potential and the extraction cost in Poland. The distribution of
favorable shale rock properties (particularly the combination of high porosity and brittle mineralogy
with low clay content) is still poorly understood and in addition, the local structural geology often is
poorly known, in particular the extent and precise location of problematic faults, which may interfere
with shale drilling and completion.
Due to the disappoint results and the complex environment, some of this company abandon the
exploration. However, is still too soon to dismiss Poland, and consequently European, shale potential:
considerable exploration drilling and seismic surveys are needed to determine the exact quantity of
technically recoverable shale gas and identifying potential sweet spots.
The main obstacle to overcome in Poland, as in the rest of the Europe, is the small amount of
reliable data present and the lack of a precise knowledge of the basin characteristics, which increases
uncertainty and poses some doubts on the profitability of shale gas recovery in the absence of an
incentive scheme. The recent fall in oil price significantly lowered oil&gas operator revenues causing
a reduction in new exploration or potentially non-economic projects. European exploration for shale
gas, at the state of the art, is considered a highly risk operation most of the major are not willing to
take on in the absence of any form of incentives or tax exemption that could, at least partially, cover
company losses.
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6.1.1. The development of Baltic Basin
According to US experience, de-risking a shale basin requires the drilling and fracturing of nearly
a hundred wells; several more to produce at a commercial level and decrease extraction costs. To date
the most exploited basin in Europe is the Baltic basin in Poland; operator drilled 34 wells and
hydraulically stimulate 12 of them(8 vertical and 4 horizontal), a number too low to understand the
geological features of a play. The low number of test well and stimulation performed in Poland reflects
the uncertainty presents that makes operates proceed extremely carefully in planning new wells. This
cautiousness, however, represent the biggest limit to the compression of the basin and its development.
In the first six years of exploration of the Barnett (from 1982 to 1988) Mitchell Energy alone
drilled and completed 41 vertical wells and none of them had a gas flow that was nearly commercially
valuable. Before technological breakthrough in 1997, when Mitchell Energy developed the silk water
fracturing, in the Barnett more than 420 had been drilled and fracturated plus several other test wells
that did not look promising for a stimulation process. When production boom happen, in 2005, the
total number of producing wells (thus excluding test wells) were of 6’584, 2’321 of which horizontal.
It is, then, easy to understand how remote would be the possibility of begin a commercial recovery
with this drilling rate; operator will have to drill lot more well to assess shale potential and begin
commercial extraction. The improvement technology, which allows drilling more efficiently with
longer horizontal section, will not reduce significantly the test well required in Europe. Is still too
soon to quantify define the European shale dream as definitely dead but it’s important keeping in mind
the effort required to assets the fully potential of a play and to develop it. Therefore, also considering
that the geological knowledge of the Barnett shale was higher that the knowledge of any European
shale basin, a lot more wells have to be drilled and completed to fully assess Polish (and European)
potential.
The US shale revolution started with a “trial and error” approach where striking a dry wells was a
matter of luck and part of the exploratory process; operators were managing to drill enough wells
every year to cover the losses. To reduce the risk associated with shale plays, improve performances
and reduce costs nearly a thousand wells have to be drilled yearly. Figure 6.1 shows the performance
improvement made by Southwestern energy in the Fayetteville shale (Arkansas) from the beginning
of the development (in 2007) to 2011. The time required to drill was halved (from 17 to 8 days), while
the lateral section nearly doubled in length (from 810 to 1’520 m) without increasing drilling
expenditure. This improvement shows how the intensity of the operation carried out in a shale play
could led to a sharp reduction in costs and a strong improvement in production, thus increasing
marginal revenue. To achieve these extraordinary results, however, Southwestern energy drilled more
than three thousand wells in four years. According to last presentation the total number of wells in the
Fayetteville shale at the end of 2014 was 4’578 with the longest latera of 1’720 m, average time require
to drill one was 6 days and the cost was kept around 2.6 million $.
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Figure 6.1 – Process improvement made by Southwestern Energy from 2007 to 2011 (Alexander T., 2011)
To have a comparison, at the end of 2013 in Poland, the average time required to drill a well with
a horizontal section of 1’000 meter well in Poland was 58 days. However drilling is not the time
consuming part of the process: the time required to obtain a permit to start drilling (from 3 to 20
month with an average of 11) and the environmental evaluation of the stimulation process (from 6 to
15 month with an average of 10). Because of the very little development of the shale industry in
Europe, cost to drilling and completion costs are much higher than the US ones; in Poland an
horizontal well cost around 16.2 million USD, five times more than in the US. The higher costs and
time required to explore and complete shale wells are not balanced with adequate flow rate able to
cover the process costs and thus company are extremely consciousness in their investments,
particularly since the fall in oil price.
Several mistakes have been made in the evaluation of the European shale gas potential and these
assessments errors sharply influenced exploration in the last years. These “mistakes” were based on
an excessive belief on the replicability of the US model elsewhere in the world. The recovery of shale
gas at a commercially valuable production rate is extremely complex: technologies involved are
relatively young and scientific analysis the process only began only a few years ago. Every shale
formation differences in its structural geology, geomechanics and mineralogy, which heavily
influence the results and the costs of completion mechanism that have to be customize according to
formation characteristics. Possessing the technology and the expertise elaborate in the US is not
sufficient to determine the success of the shale gas exploration elsewhere in the world. If Europe want
to exploit its shale sources, it will have to improve North American methodologies applying them to
the different contest in which operation are placed. The shale gas boom in the US was determined by
the combination of different technological, economic and social factors which, together created a real
revolution: the long and painful phase of exploration and technological testing started in the early
eighties and took more than thirty years from the first attempt to the real boom.
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6.2. US success factors and European limits
A long exploratory phase is required in Europe before shale gas extraction could reach a
commercial phase. This should not come as a surprise; the shale gas revolution in the US did not
happen overnight but took nearly thirty years to reach visible level. The technological transfer will
surely speed operations up but it would be nearly impossible to replicate the US success. Europe could
find its own way towards shale gas exploitation keeping in mind limits and challenges.
The success of shale basin depends essentially lies mainly in two main aspect: the amount of gas
in place and the formation response to hydraulic stimulation. As mentioned in chapter 4 these aspects
are called reservoir quality and completion quality.
Reservoir quality (RQ) determines regards the quantity of hydrocarbons in place. The parameters
that influence RQ are: organic content (TOC), thermal maturity, effective porosity, organic shale
thickness and water saturation.
Completion quality (CQ) the higher completion quality the higher would the artificial permeability
increasing the quantity of hydrocarbon recovered. It includes shale mineralogy (high amount of clay
tend to make shale structure more ductile thus lowering the effect of the hydraulic stimulation),
mechanical properties of the formation and the presence and orientation of natural fractures.
Vast gas reserves the presence of an adequate technology to extract them are the “sine qua non”
conditions were of the US success.
Shale revolution, however, was made possible by other factors. Understanding the conditions that
have made shale gas exploitation successful in North America is fundamental to determine the
European potential. Vast reserves of shale gas, efficient drilling and completion technology and the
large geographical space, which enabled the drilling of hundreds of thousands of wells, were key
favorable conditions for large-scale development of unconventional gas resources, but were not the
catalysts.
Five factors have been the main catalyst that triggered this surge in shale gas production. On the
policy side, these are: government supports trough state and federal policies, founding of different
R&D initiative, clear and industrial-friendly regulations and a favorable ownership of mineral right
that simplify the access to private land. On the market side, the reasons that transformed this business
into the most profitable one of the last decade have been: easy access to a credit market, large amount
of operators involved in this business, high competition present in the service industry and access to
infrastructures given by a completely liberalized gas market.
The assessment of the relative importance of these factors goes beyond the goal of this work it is
clear that that while favorable policies, prices, credit markets and support services provided the right
framework for the shale gas boom, technological breakthroughs was what provided the immediate
production surge.
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6.2.1. Technology development
Exploitation of gas shales is a high-tech undertaking: for a large part of the century, shale have
been studied as source or cap rocks. Despite the amount of hydrocarbons in place, these formations
were considered impermeable and impossible to access: the combination of two existing technology
reversed this conception. In the Barnett, water fracture stimulation was applied from 1997 and in
combination with horizontal drilling from 2003. Another important improvement, although less
mentioned that the previous, was the improvement in prediction of gas concentration, rock properties
and formation behavior in response to hydraulic stimulation operate through seismic survey and
improve reservoir modelling. The ability to model a reservoir based on seismic data without the need
of drilling test wells greatly reduced exploration costs and allowed operators to identify target “sweet
spots” reducing risks and increasing production outcome.
Shale boom was not only influenced by the presence of the technology but also by the rapidity
with which these technology widespread. In the oil&gas industry, innovative technology (such as 3D
seismic and horizontal drilling) typically requires an average of 30-35 years to pass from concept
development to commercialization. Shale gas related technology required less then decade to pass
from development (late 1990s) to widespread application (around 2006).
Figure 6.2 - Growth in the number of horizontal wells and customized technologies (2010 Land Rig Review)
This concept is illustrate in figure 6.2: it shows the exponential growth of new producing wells in
the Barnett at the beginning of the millennium and the quick switch from vertical to horizontal wells.
The graph also shows the technological leap that allowed the success of shale gas recovery and the
increasing percentage of drilling rig able to perform horizontal drilling within the US rig
fleet.Technology was the key to unlock shale potential and will be the single main driver to future
production growth. Declining wells productivity, high risks and failure rates in shale plays and
environmental concern would require improvement in technologies to improve performances, reduce
risks and comply with stricter standards and regulation.
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6.2.2. Federal and State policies
Policies set in place by federal government has been fundamental in supporting domestic
unconventional gas exploration and extraction. Tax policies played a major role in supporting
production from unconventional source that would have not been profitable if only dependent on
market conditions. The key fiscal measures targeting production from unconventional sources and
small independent are essentially four:
(i) - “Section 29”: also called “Alternative Fuel Production Credit” (Section 29 of the “Crude
Oil Windfall Profit Tax Act”) was introduced in 1980, with the aim of reducing dependence on
energy imports encouraging the production of domestic energy from unconventional sources. Credit
value ranged from $0.90 to $1.08/mcf during the nineties increasing operator revenues of 53% with
respect to wellhead price. The companies that reported receiving Section 29 tax credits overall
quadrupled their rate of onshore natural gas drilling between 1986 and 1990, from slightly under
400 natural gas well completions per year to about 1,600.
(ii) - Small Producers Tax Exemption: also known as the "Percentage Depletion Allowance",
included in the 1990 Tax Act. This tax incentive was available only for the first 1,000 barrels/day
of oil or 6 million cubic feet of gas of domestic production. This tax exemption allowed 15% of the
gross income from an oil and gas producing property to be tax- free, providing capital for small
independents.
(iii) - Marginal Well Tax Credit: in is a tax credit enacted in 2004 to create a safety net for
marginal wells42 to avoid their premature closure and plug during periods of low price. Marginal
wells, in fact, provide an important contribution to the US domestic production accounting for 12%
of natural gas and 20% of oil total production.
(iv) - Intangible Drilling and Development Costs (IDC) Expensing: IDC includes any cost
incurred for the preparation of the drilling site or the phase drilling of wells without any salvage
value43. Costs includes mainly seismic surveys and rig day rates and accounts for two-thirds of total
drilling costs. The companies that benefits from this fiscal measure are high-cost producers with
intense drilling activity basically independents exploiting unconventional gas.
Beside the favorable credit and tax exemptions for independent and companied operating in the
unconventional hydrocarbons, the US government funded several pilot project and R&D initiatives.
The Department of Energy (DOE) initiated a research program targeting unconventional gas
formation in 1978. One of the program component was the Eastern Gas Shales Program that was
targeting shale formation the Appalachian, Michigan, and Illinois Basins. These shales formation are
relatively shallow and easily accessible, and have been exploited since the 1920s. Technology
employed was “low cost but technically simple and ineffective”; the industry had a poor understanding
42 A marginal well (also called stripper well) is an oil or gas well that is nearing the end of its economically useful life. Because of their marginal economic these wells are the most vulnerable to permanent shut-ins when prices fall. 43 Savage value is the estimated value that an asset will realize upon its sale at the end of its useful life. It is used in accounting to determine depreciation amounts and in the tax system to determine deductions.
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of the physical and chemical characteristics shale, and the estimates of recoverable reserves were
highly uncertain. The purpose of the program was “to assess the resource base, in terms of volume,
distribution, and character and to introduce more sophisticated logging and completion technology to
an industry made up mostly of small, independent producers.” Technologies developed in the Antrim
shale was then transfer and successfully applied to the Barnett and other shale basins.
6.2.3. E&P regulation
Exploration and production of oil and gas in the U.S is regulated under a complex set of federal,
State, and local laws that address every aspect of the process. All the laws, regulations, and permits
that apply to conventional oil and gas exploration and production activities also apply to shale gas
development. The US Environmental Protection Agency (EPA) administers most of the federal laws
but most oil and gas development regulations are currently left to States, where regulatory bodies are
responsible for designing and enforcing regulations specific to oil and gas production as well
environmental laws. E&P regulations involve well permits, well spacing, application of given
operational standards and practices during well construction, hydraulic fracturing, waste handling and
well plugging, tanks and pits, as accidental chemical or waste water spills. All these federal laws grant
“primacy” to the States (i.e., State agencies implement the programs with federal oversight) because
every State can more effectively address the regional and State-specific characteristics of E&P
activities tailing regulations to local investment conditions (geology, topography, population density,
local economics, etc.) and the needs of local operators.
6.2.4. Access to land and infrastructure
The vast majority of shale gas produced in the United States comes from State and privately
owned lands, which guarantee a relatively unconstrained access. Contrary to Europe, private
landowners own their mineral rights, meaning that all valuable minerals or hydrocarbons present in
the subsoil within the border of their property belong to them. The landowner could lease their land
to oil and gas company authorizing them to extract such hydrocarbons. Accessing private land is,
t h e r e f o r e , only a matter of contractual negotiations between operators and private individuals,
which have an enormous financial incentive to lease their property. Common Gas leases include
signature bonuses, royalties (from 18 to 25% of the total gas extracted depending on the States),
rents, primary lease terms and conditions for lease renewals. Second, access to State-owned land
primarily takes place through lease auctions organized by States. States are already set up to manage
oil and gas operations within their jurisdiction, so no special permitting or enforcement systems
are required. In conclusion, the ownership nature of the land where shales are located has been
making land rapidly and quite freely accessible for operators.
Other fundamental aspect is the easy access to pipeline capacity, which, due to market
deregulation and the high amount of gas-to-gas competition, is straightforward process. An operator
can simply negotiate with the pipeline company a connection with the main pipeline, regardless of
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how much capacity is available or booked. In Europe, the midstream situation is very different,
despite the implementation of the TPA contained in the 2011 Third Energy Package several
restriction remains. Gas to gas competition is still weak and access to transmission capacity in Europe
is typically controlled by large national utilities and governed by a series of heterogeneous national-
level regulations. Several areas where shale gas exploration is taking place are poorly connected with
distribution or transmission network. In case of shale gas commercial extraction operators would
have to build (or co-founding the construction) of pipelines to transport their gas.
6.2.5. Highly competitive service sector
Shale gas plays require significant more rigs, fracturing equipment and specialized staff operating
them than conventional fields. The fast development of shale plays could not have taken place if the
service industry, in particular land drillers and completion service providers, had not been able to
invest quickly in equipment improvement. Improvement in rig design allowed the drilling of more
wells from a single pad, with longer laterals in a reduced amount of time thus decreasing sharply
project costs. Operators greatly benefited from this cost reduction and improvements in production
results. The technological improvement have been realized extremely quickly in order to keep up
with shale operators demand: the share of US onshore rigs having a horizontal drilling capability
increased fivefold in 10 years, from 6% in 1998 to close to 30% in 2008.
Such improvements would hardly be seen in Europe; oilfield service market is smaller and
investments in improved rig design are discouraged by the uncertainty surrounding shale gas projects.
Europe has 133 rig with only a fraction of them able to perform horizontal section and 8 fracturing
equipment, compared to the nearly thousand-oil rig active and the 600 fracturing equipment present
in the US. Any eventual increase in the European exploration activity for shale gas or any commercial
scheme would require the implementation of the European rig fleet.
6.3. The European way to shale gas
In Europe, situation is very different with respect to the US: reserves are less abundant and shale
plays are smaller, more fractionated, with a more complex geology and mineralogy. Knowledge of
formation behavior is weak and the amount of exploratory data insufficient to perform a reliable
evaluation of the resource present. Government support, environmental regulation and market-based
factor are all less attractive with respect to the US. Despite the dream and the claims of shale supporter
Europe will not be able to replicate the US model.
The golden scenario of vast amount of cheap gas able to lower energy price and improve energy
security foreshadowed by shale enthusiastic is merely a dream. On the other hand, shale opponents
focused on the environmental impact of hydraulic fracturing and the high population density, none of
which is the challenge Europe will face in order to develop its own unconventional gas industry.
118
The main limitation regard the lack of a common legislative framework or policy aimed in
supporting unconventional exploration. Regulation of European gas market is still an ongoing process,
particularly in Eastern Europe where the limited amount of player acting like monopolist limits gas-
to- gas competition, and gas network is less developed that the one in the US creating problems related
to transport capacity. In addition, European service market would require a significant improvement
to be able to sustain a widespread exploration phase or the beginning of a commercial recovery.
In conclusion, Europe has potential but due to the low amount of reliable data on play geology,
the lack of a common European supporting scheme and the high cost involved increase uncertainty
relative to the profitability of the process.
6.3.1. The European model
Europe has no technological expertise of its own and will have to transfer technology from North
America; however, geological differences (basins are generally deeper, hotter, more highly
pressurized and with a higher clay content) make the application of US technology not
straightforward. Transfer of US drilling and stimulation technologies would surely take place, but its
application would require several adjustments to become effective.
The US model has been (and on a certain amount still is) pro derived from empirical approaches
(trial and error); Europe could not follow the same path but would have to develop a more scientific
approach. The smaller concession site and the higher population density would limit the number of
test wells needed to assess shale potential. To improve their knowledge while minimizing the number
of test wells to be drilled operator have to invest more in R&D to improve and customize
characterization technology such as 3D seismic, reservoir modelling, and monitoring technology. The
development of technologies customizes on European basins would not come from an empirical
process but rather from a more scientific one based on subsurface characteristics evaluation.
6.3.2. Evolution rather than Revolution
Despite the interest aroused in other world country, it is almost certain that the US model would
not be replicate elsewhere: this revolution was the results of a complex set of factors joining together
that generate unexpected results. Technology, expertise in the oil and gas sector and a relatively simple
geology had been the main key; however, this result would not have been achieve without other
important catalyst such as supporting policies, favorable tax exemption and credit, fast land
negotiation, landowner support and a high amount of competition within natural gas and oilfield
service markets .
Elsewhere in the world condition are more complex on each of these aspect, requiring the creation
of a specific and country based model. Limited technological transfer, poor knowledge of shale
formation geology and behavior and a considerable less expertise in the unconventional sector set all
other potentially shale rich country far behind the US.
119
Extraction of unconventional hydrocarbons will not be, then, the solution to all energy related
problems of the European Union but could help in compensating the decline of conventional
production reducing the dependence on foreign exports. The impact of shale gas in Europe would
unlikely became a “game changer” able to transform the whole energy market as a whole, as it happen
in the united states, but it could be significant for individual country. Impact on single energy markets
will differ from country to country, depending on their national energy strategy, amount of natural gas
within the energy matrix, import dependence, social acceptance and alternative gas sources. While
there has undoubtedly been a shale gas revolution in the US, shale gas development in Europe will
follow a more evolutionary path.
Table 6.1 –Shale gas in Europe and the US – Revolution vs Evolution
US – Shale Revolution Europe – Shale evolution
Geology and
resource potential
Early exploratory success
Reserves potential greater than expected
Rapid ramp-up in production
Disappointing well results
Reserves found to be uneconomic
Unsustainable production rates
Environmental
worries and
social factors
Public desire for lower energy price and
higher energy security
Increased public pressure on
government to halt shale
exploration and hydraulic
fracturing
Fiscal and
regulatory regime
Incentives provide on federal and state
level to operators
Government support of R&D programs
Lack of incentives on federal or
state level
Heterogeneity in regulation and
policies
Energy prices and
gas market
Extensive gas-to-gas competition in gas
market
High market spot liquidity
Interconnection between gas market
Limited amount of gas to gas
competition
Low share of spot trading
Insufficient interconnection
between markets
Gas demand Growing gas demand for industrial and
power generation application
Decrease of gas consumption
because of the slow Eurozone
economic growth
Service industry
Densely populate and highly
competitive market
Quick technological development
resulting in lower well per-well costs
Limited supply of adequate
equipment and skilled personal
Lack of funds available to improve
or enlarge equipment fleet
120
121
Chapter 7
General conclusions and implications for
European gas market
Since the nineteens environmental protection has become one of the pillar of European energy,
policies and topic such as local pollution or global warming have become widespread knowledge
worldwide. Several measures, such as Kyoto protocol or Euro 20/20/20, have been take to reduce
greenhouse gases emission and halt global warming. To date, covering the 100% energy consumption
with renewables sources is technologically impossible; however, the need to decrease the carbon
footprint of global economy remains. In the short-term horizon, a progressive substitution of oil-based
fuels or coal with natural gas would bring greater benefits to both local and global pollution, as the
case of the United States demonstrated.
The biggest constrain in an increase reliance on natural gas is the structure of its market. Due to
the complexity and costs involved in its transportation, natural gas market evolved regionally with
almost no connection between them; these markets are often controlled by a reduce number of
exporting country operating with a close to monopoly scheme.
The incredible rise of unconventional gas production in the US revolution energy landscape. The
US are currently experiencing their all-time higher natural gas production with dramatic effects on the
economy and the domestic natural gas market. Not surprisingly, this success rose the interest of many
other country worldwide; shale resources are, in fact, more abundant the conventional ones and more
widespread. Between the frontrunner in the shale gas exploration, there are several European
countries; aiming to develop an unconventional industry in order to decrease its high depends on
foreign imports. European dependency on extra-Eu countries reached 65% of total consumption and
recent geopolitical events are threatening European security of supply.
Despite the promising reserves held within shale formation, no commercial recovery has yet began
and a long exploratory phase is still needed before extraction could ramp up becoming economic.
Understanding factors and conditions behind the North America success is fundamental to understand
the potential and the challenges that European unconventional production will face. Five catalysts,
related to the nature of US natural gas market and on the associated policies and regulation, triggered
modern unconventional gas production. The large number of major and small independents guarantee
a high concurrence in both oil&gas and oilfield service market.
- The deregulation of domestic gas market, the high gas-to-gas competition and the availability
of infrastructure guaranteeing a certain economic return for operators.
- Fiscal policies incentivizing operators to join the shale gas business
- An US industrial-friendly regulatory frameworks granted freedom to operators to develop the
cheapest possible practices.
122
Between these catalyst technological improvements have been the major driver. Technology will
be the main driver to future production growth in the US and elsewhere in the world, improving
operational efficiencies, wells economics and mitigating the impact of operations on the environment
and local communities.
European political and socio-economic context is very different from the US, and the differences
are rooted at all institutional levels: national, regional and local. Europe will have to develop its own
model and investment conditions for unconventional gas resources. US practices would remain as
reference and new technologies test field, but the shale gas industry have to be adapted to the European
contest. In Europe, while hopes are still high, the unconventional gas industry has to overcome many
severe and regionally specific challenges before unconventional gas can be produced in
significant quantities. European shale subsurface conditions significantly limit the transferability of
the US experience to the continent. The lack of geological information on shale deposits is the first
challenge to address, a situation that is similar to the US thirty years ago, when it started mapping its
own resources in the 1980s. There probably will be a long and painful testing phase in Europe similar
to the US, driven by commercial catalysts, as technology from the US is already available. The stage
of immaturity of unconventional gas in Europe combined with unique space and cost challenges, calls
for investments focusing on decreasing geological risks ahead of drilling in all phases, exploratory,
appraisal and development. Land access and cost levels are the two major differences in the general
surface conditions between Europe and the US. Finding and development costs in Europe are expected
to be 2-3 times higher than in the US, while drilling and completion cost could be more than 5 times
higher. Even if reductions and optimization can be expected, these will be limited by strict and
heterogeneous regulations, high costs of services due to limited competition in the sector, and a
potentially insufficient number of operations. Determine which would be the breakeven price of
European shale is highly speculative at the state of the art, however it is certain that, without a
significant change in the gas market structure or in the supporting policy of state or Eu council
unconventional gas is unlikely to be develop. In fact, contrary to the US the more active companies
in Europe are oil major, which have a very cautious approach the new exploration and would probable
switch to other investments.
The final challenge to the large-scale development of these resources is linked to the limited
capacity of the service industry in terms of equipment and qualified staff; equipment would surely
brought from North America but the personnel issue remains an important uncertainty. Due to the
different nature of the operators and surface issues, the European response to all the challenges
mentioned above will be based on a different model to the US model. The response has to come from
both the market and governments. While some hurdles can be overcome by the market if the
investment climate is favorable, changes will ultimately depend on political priorities, at a national
and EU level. However, socio-economic and political situations between countries are very different,
and countries which have the highest import dependency on Russian gas could be expected to
implement policies fostering the development of their unconventional resources before others.
123
In order to develop its own unconventional industry Europe will have to face several challenges
and improve operations. The most important aspect that have to be considered are the following:
- The development of new and more efficient technologies to improve extraction rate, reduce
cost and mitigate land consumption
- Improve land access and lease negotiation trough the support of local communities:
landowners should be compensate for the disturbance with adequate financial instruments
- Improve the communication to solve the worries related to the environmental impact with an
extensive media campaign aimed in clarify the real risk of shale gas operation thus allowing
the general public to evaluate pro and cons
- Modifying or introducing new policies in order to simplify all the process and request related
to the E&P application
- Invest in technological R&D aim in improving the understanding of the physics behind shale
operation
- Introduce a subsidies system in order to stimulate operator interest in exploration of shale gas
resource while guarantying a partial return in the investment
- Develop a service segment with local trained workforce and greater manufacturing capacity.
Whether unconventional gas can be a game-changer for Europe depends on the production level
that is considered realistic, and conclusions at this stage remain speculative due to the very early stage
of development. The effects of new gas production from unconventional sources are likely to be the
strongest within Continental Europe. Unconventional gas might not be able to transform the entire
European market, but it should shift regional dynamics within the continent: it will not be sufficient
to guarantee the energy independence of these countries but it will definitely improve the local gas-
to-gas competition contributing to develop the European gas market as a whole.
124
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