UNIVERSITY OF GOTHENBURG
Department of Earth Sciences
Geovetarcentrum/Earth Science Centre
Unconventional gas and oil
- in the USA and Poland
Jakub Leśniewicz
ISSN 1400-3821
Mailing address
Geovetarcentrum
S 405 30 Göteborg
Address
Geovetarcentrum
Guldhedsgatan 5A
C90
Project
Göteborg 2012
Telephone
031-786 19 56
Telefax
031-786 19 86
Geovetarcentrum
Göteborg University
S-405 30 Göteborg
SWEDEN
Unconventional gas and oil – in the USA and Poland
Jakub Leśniewicz, University of Gothenburg, Department of Earth Sciences; Geology, Box 460, SE-405 30
Göteborg
Abstract
Despite the fact that the exploitation of natural gas from unconventional deposits is much more difficult and less
economically viable than from the conventional reservoirs, they are now a very attractive target. This is due to
the gradual depletion of conventional resources, and large deposits of natural gas in unconventional reservoirs,
which previously were not known or there was no technology that allows to explore them. Coalbed methane ,
tight gas and shale gas have been successfully developed in the United States over the past two decades. The
initial increase in the production of unconventional gas, shale gas in particular, was then maintained through the
use of horizontal drilling and hydraulic fracturing, as well as an increase in gas prices. Production of shale gas
has a greater deposits potential, while lower productivity and higher cost of drilling, as compared to conventional
gas, which is associated with a more cautious investment strategies. Shale gas exploration strategies are also
different from those of conventional gas and, initially, require an extensive source rock analysis and a big land
position to identify “sweet spots”. Searching for shale gas in Poland is focused on the formation of the SilurianOrdovician age that are poorly diagnosed and thus characterized by a high exploration risk. Therefore,
exploration companies have used a cautious approach which is reflected in planning of the concession activities
divided in a few phases, with each successive phase contingent on the positive results of the preceding one.
These phases include analysis of existing data, seismic surveys, exploratory drilling with an extended analysis of
the cores prior to using horizontal drilling. On a technical level of shale gas exploration, the integration of many
disciplines is required for commercial success. There are several obstacles to the exploration of shale gas in
Poland, including: regulations which are in favor of the domestic service companies impeding competition,
changeable and unclear environmental protection regulations, as well as insufficient liberalization of the
domestic gas market.
Keywords: Unconventional gas, unconventional oil, USA, Poland
ISSN 1400-3821
C90
2012
5.2.9. Occupational Safety and Health Act (OSHA)........................................................ 30
6. Environmental concerns ....................................................................................................... 31
6.1. Risk of shallow freshwater aquifer contamination, with fracture fluids ....................... 31
6.2. Risk of surface water contamination, from inadequate disposal of fluids returned to the
surface from fracturing operations ....................................................................................... 31
6.3. Risk of surface and local community disturbance, due to drilling and fracturing
activities ............................................................................................................................... 32
6.4. Risk of atmosphere contamination ................................................................................ 32
6.5. Earthquakes ................................................................................................................... 33
7. Shale gas in Europe .............................................................................................................. 34
7.1. Shale gas in Poland ....................................................................................................... 35
7.1.1. Geological condition .............................................................................................. 37
7.1.2. Risks and problems ................................................................................................ 40
8. Conclusions .......................................................................................................................... 43
9. Acknowledgements………………………………………………………………………...44
10. Figures and tables ............................................................................................................... 44
11. References .......................................................................................................................... 46
1. Introduction
In view of diminishing stocks of hydrocarbons in Poland, as well as few new areas of
exploration, a study of lesser known or ignored resources is called for. To diagnosis, and
extract, these unconventional resources it is necessary to develop research methods and
technology that will assist in their exploitation. Shale gas is natural gas contained in the
organic diagenetic silt-clay rocks, with very low porosity and very low permeability. A
characteristic feature of shale gas, that sets it apart from conventional natural gas
accumulations, is a lack of spontaneous flow of gas to a drilled well in quantities in which
exploitation would be economically justified. By the end of the 80s accumulations of this type
have not been the object of particular interest to explorers. In the last two decades, the
increase in oil prices and the invention of new technologies, with lower cost of horizontal
drilling and treatments that stimulate the gas flows into the well, a steady growth in world
natural gas production from such deposits is seen. The importance of unconventional reserves
in the world is increasing constantly. In the United States - a country with the most developed
oil industry, the focus on unconventional sources of hydrocarbons - shale gas resources
constitute a significant part of the total recoverable natural gas resources. But, new
discoveries is rapidly increasing this percentage. Shale gas production in 2006 was almost
three times higher than in 1996. Besides American companies, only a few large international
companies can today efficiently exploit these deposits. One obstacle is the high costs of
drilling horizontal wells at great depths (often in excess of 3 km) and complicated and
expensive hydraulic fracturing rock technologies (creating artificial cracks). This new
“fracking” technique creates a network of fractures, spreading concentrically from the hole,
even for a few hundred meters, in order to connect as big a volume as possible of the rock
with the hole.
1
2. Hydrocarbons
Hydrocarbons are organic compounds consisting of carbon and hydrogen atoms. The carbon
atoms form a skeleton to which the hydrogen atoms are connected by bonds. Because of the
differences in carbon skeleton we are able to distinguish several kinds of hydrocarbons. In
petroleum, the most relevant ones are alkanes (CnH2n+2), naphthanes (CnH2n) and aromatics
(CnH2n-6). The first two groups are called saturated because of the single bonding between
carbon atoms hence there is no possibility to connect another atom. The third group comprise
compounds which have multiple bonding between carbon atoms, therefore considered
unsaturated, and other components can be joined. Under normal surface conditions
hydrocarbons can occur in different physical states. It depends on the molecular weight of
each compound. The lightest ones like methane or ethane always appear as gases. Some of the
aromatic hydrocarbons may be liquids, while the heaviest among occur as solids. The light
alkanes and nephthanes may change their physical state to liquid or even solid if subjected
high pressure and temperature. Hydrocarbons originate from organic matter, subjected to
anaerobic conditions and diagenetic temperatures for millions of years.
2.1. Fossil fuels
There are three main types of fossil fuels: coal, crude oil and natural gas. Basically, the
processes of creation are similar for all of them, though some factors indicates differences
between them. All fossil fuels require extremely long periods of time to be created, under
elevated pressure and temperature and absence of oxygen. Favorable geological conditions in
turn are necessary so the fossil fuels may migrate and concentrate. All of the elements listed
above together are called a petroleum system. It encompasses also geological processes like
trap
formation
and
generation-migration-accumulation
of
hydrocarbons
(fig.
1.)
[Magoon & Beaumount, 2003]. The organic remains are buried under sediment layers in
sedimentation basin as a source rock. Then during millions of years the organic matter goes
through numbers of chemical and physical processes and finally changes into hydrocarbons.
After this happened hydrocarbons migrate using pores and openings in rock to a reservoir
rock where they accumulate.
2
Fig. 1. Scheme of hydrocarbons reservoir creation [a]
In order to prevent them from further migration there must exist a barrier or seal above and
around them of impermeable rock. Shale, anhydrite, salt and mudstone are usual seal rocks.
Hydrocarbons might be trapped also by structural traps (fig. 2.). These include such features
as folds (e. g. anticlines), salt domes or tilted fault blocks.
Fig. 2. Different types of structural traps [Wang & Economides, 2009]
3
2.1.1. Kerogen
Kerogen is a naturally occurring mixture of organic chemical compounds contained in the
source rock. Its high molecular weight makes it insoluble in organic solvents. If heated to
temperatures of 60-160 °C it can release oil and to temperatures of 150-200 °C gas. During
petroleum generation from kerogen bitumen is formed. Unlike kerogen, bitumen has a low
molecular weight and can be dissolved in organic solvents. There are four major types of
kerogen depending on hydrogen/carbon and oxygen/carbon ratios (fig. 3.):

type 1 consists mainly of algal matter and is formed from proteins and lipids. It
is most likely to produce liquid hydrocarbons,

type 2 comprises both marine and terrestrial organic matter and can generate
oil as well as gas,

type 3 is formed by terrestrial woody material and tends to produce coal,

type 4 is called residual and does not produce hydrocarbons [a, b].
Fig. 3. Evolution of kerogen [c]
4
2.1.2. Crude oil
Billions of microscopic organisms called plankton live in the oceans. After they die their
remains fall down on the ocean bottom. With time these remains become buried deeper and
deeper under sediments. After a while the sediment layer acts like a barrier and makes gas
exchange impossible to happen hence there is no oxygen available in the organic layer. Under
these anaerobic condition associated with increasing pressure and temperature, organic matter
is converted firstly into a kerogen type 1. As times goes kerogen is continuously subjected to
increasing pressure and temperature and finally is transformed into crude oil. This process
may occur at depths of 6,5-9,5 km beneath seabed. Then, if the conditions (reservoir rock, cap
rock etc.) are favorable, the crude oil might focuse in some areas creating reservoirs.
Sometimes the crude oil may migrate from reservoirs thanks to faults even up to the
surface [r].
2.1.3. Coal
Unlike crude oil, coal origins from terrestrial plant remains. If trees, bushes and other kinds of
woody plants died in swamp areas and were quickly covered by sediments, they could
became an initial material for coal beds. The conditions prevailing in such buried swamps
preserved the material from complete decay. As temperature and pressure slowly increased
during time, the buried organic matter was gradually transformed into different coal types
with increasing content of carbon. As opposed to crude oil, coal can be used to produce heat
and energy at every level of conversion. It is possible due to even small content of carbon can
be burned. Since there is different amounts of carbon present at each stage of transformation,
several types of coal can be distinguished. These are (following the increasing content of
carbon):

lignite – 25-35 %,

subbituminous – 35-45 %,

bituminous 45-85 %,

anthracite 86-98 %.
The higher the carbon content, the more energy is released during burning [p].
5
3. Natural gas
The term natural gas refers to a colorless and odorless heterogeneous mixture of several
chemical compounds. The main components are compounds from the group of light
hydrocarbons mainly methane but also ethane, propane and butane. They may constitute
nearly 100 % of the total. Among other components we can usually find such compounds as
carbon dioxide, nitrogen, hydrogen sulphide [d]. Table 1 shows the typical composition of
natural gas. Two types of natural gas could be distinguish based on the differences in its
content. These types are:

wet natural gas – consists of a number of chemical compounds, mostly hydrocarbons,
sometimes also some amount of liquids; it requires some processing before it can be
used,

dry natural gas – forms devoid of almost all components but methane; this form is
piped to homes, factories and other end-users.; it results from refining the wet natural
gas derived from natural sources. Due to safety issues, in order to make natural gas
detectable, mercaptan, an odorant compound is often added.
Table 1. Typical composition of natural gas [d]
Methane
CH4
70-90 %
Ethane
C2H6
Propane
C3H8
Butane
C4H10
Carbon ioxide
CO2
0-8 %
Oxygen
O2
0-0.2 %
Nitrogen
N2
0-5 %
Hydrogen sulphide
H2S
0-5 %
Rare gases
A, He, Ne, Xe
trace
0-20 %
3.1. Origin
There are several theories considering origin of natural gas. Like other fossil fuels, natural gas
may be created by transformation of organic matter exposed to elevated temperature and
pressure under anaerobic conditions. However, contrary to other fossil fuels it may originate
6
from terrestrial plants as well as from marine phytoplankton and zooplankton remains. Then
using pores and openings in rock as pathways, gas migrates upwards until it reaches a barrier
formed by cap rock overlaying the reservoir rock. For natural gas to be created, higher
pressures and temperatures are required than for crude oil. It means that it can be formed
deeper under the surface. It is quite common, however, to find an association of both natural
gas and crude oil in shallower reservoirs (fig. 4.). Also coal beds may occur together with
some quantities of natural gas. Just like in the case of other fossil fuels, supplies of this kind
of natural gas are considered as non-renewable since it takes millions of years to create them.
Fig. 4. Zones of natural gas and oil creation [e]
Natural gas can also be produced in a bit different way. Very common sources are landfills,
manure digesters and wastewater treatment plants (fig. 5.). It is created by the decomposition
of wastes. Microorganisms convert organic matter under anaerobic conditions [q]. Since it is a
result of human activity its great advantage is that it is a renewable source which is important
today.
There is also another way in which natural gas is created. It is produced in rice fields and
swamps by decaying dead organic matter. Natural gas is also one of the by-products of cattle
and termites digestion processes. Unless captured and stored these are useless for economical
purposes [q]. These two last kinds of natural gas are often called a biogas.
7
Fig. 5. Scheme of installation for natural gas use [f]
3.2. Reservoirs
Considering the type of reservoir rock, form of accumulation and exploring possibilities two
major types of gas resources can be distinguished: conventional and unconventional.
3.2.1. Conventional reservoirs
Conventional reservoirs of natural gas (or/and crude oil) are the ones in which hydrocarbons
are trapped below impermeable cap rock (fig. 6.). The natural gas accumulations are usually
trapped by structural or stratigraphic features. The reservoir rock is a sedimentary rock,
predominantly sandstone and limestone. It must be characterized by high porosity with pores
connected to each other in order to allow gases and liquids to flow free through them. Since
hydrocarbons are under great pressure, the only action necessary to extract them is to drill a
bore hole and put pipelines into it, so they flow up to the surface. After some amount of
accumulated gas is pumped from the reservoir the pressure inside the reservoir decreases and
a boosting of pressure is required to continue production. Higher pressure is commonly
achieved by injecting water or other gases. Today, a very popular method is pumping down
carbon dioxide and by this also store it under the earth’s surface. This also achieves reducing
a quantity of this greenhouse gas in the atmosphere.
8
Fig. 6. A typical geological formation in which natural gas can be formed in association with crude oil
[Magoon & Beaumount, 2003]
3.2.2. Unconventional reservoirs
Unlike conventional the unconventional gas cannot freely move within the storage rock. It is
contained in the rock free spaces and openings, but they are not connected with each other as
much as in the conventional reservoir rock. Usually, but not always, unconventional resources
of natural gas are stored at greater depths hence they are subjected to higher pressure. Because
of that this sort of gas is much more difficult to extract and its exploration is not as much
profitable. There are five main types of unconventional gas accumulations: tight gas, coalbed
methane, methane hydrates, geopressurized zones and shale gas. Resources of unconventional
gas are referred as low quality ones. As with other natural resources, low quality deposits of
natural gas require improved technology and adequate gas prices before they can be
developed and produced economically. However, the size of the deposits can be very large,
when compared to conventional or high-quality [Holditch, 2007] (fig. 7.).
9
Fig. 7. Resources of conventional and unconventional gas [g]
Tight gas
Tight gas just like conventional gas is accumulated in sedimentary rocks like sandstones or
limestones. The difference is that the rock within which tight gas is accumulated is much
more impermeable and has lower volume of free spaces between grains (fig 8.). This type of
natural gas usually is not associated with crude oil. Exploration of tight gas requires special
technology including horizontal drilling and hydraulic fracturing [h]. Some companies use
combination of two bore holes located at some distance between each other. Through one of
them water or other substances are injected in order to wash the gas out from between grains,
while the second bore hole is used to suck the washed gas up to the surface.
Fig. 8. Visualization of trapped gas (blue) in unconventional (left) and conventional (right) reservoir rock
[i]
10
Coalbed methane
Coalbed methane is type of natural gas that is trapped within coal seams and consist almost
exclusively of pure methane. It got there during the coal creation processes and did not
migrate from the coal bed to other sedimentary rocks located in its surrounding. Because of
the specific structure of coal beds they can store even up to seven times more that the
conventional rocks [q]. Usually as opposed to other types of natural gas, coalbed methane
appear at the relatively low depths. It can be explored by using similar techniques as are used
to extract shale gas. Coalbed methane despite its advantages is one of the main hazards during
the activities associated with coal mining. As it is highly flammable it is often cause of
explosion [h].
Methane hydrates
Another form of unconventional natural gas is a chemical compound consisting of methane
molecules surrounded by water molecules, called methane hydrates (fig. 9.). It mainly occur
as a solid crystalline “ice” below the ocean’s floor in the arctic regions. This is the most
abundant of methane form of natural gas but also the hardest to reach and the most expensive
to explore. Scientists are worried that rising global temperatures may destabilize the deposits
causing the release of great amounts of methane, which is one of the main greenhouse gases,
to the atmosphere [q; h].
Fig. 9. Methane molecules trapped inside the water molecules cages [j]
11
Geopressurized zones
Geopressurized zones are typically located at great depths even up to 7500 m below the
earth’s surface. They are formed by rapid deposition and further compaction of clay material,
and consists of water and gas. If the clay layer overlay more porous sediments like sand or
silt, compressed water and gas migrate from clay layer to layers lying below it. Hence
accumulations of natural gas in those formations are under enormous pressure. Because of
these properties extraction of natural gas in geopressurized zones is extremely
complicated [k].
Shale gas
Shales are a type of fine-grained sedimentary rock, which are mostly built by consolidated
clay-sized particles. Shales originate in low-energy depositional areas like deep water basins.
During the deposition of their mineral particles, the organic matter can also be deposited.
Since clay grains has tabular shapes, they tend to lie flat on each other, causing the pore
spaces between them to be very small. As the deposition process progress more and more
sediments are piled over the existing ones. It causes that the grains are continuously
compacted and free spaces between them become smaller over the time. This results in a
horizontally laminated shale rock, which has extremely limited vertical permeability (fig.
10.). This low permeability means that gas trapped in shale cannot move easily within the
rock. Because of these properties, shales are formations that were in the beginning considered
just as source rocks and cap rocks for gas accumulating in the conventional reservoirs and not
as potential storage of fossil fuels [GWPC, 2009].
Fig. 10. Macroscopic (left) and microscopic (right) view of shale rock [l]
12
The majority of shale gas form from transformation of organic matter under rising pressure
and temperature and is referred as thermogenic gas. In some cases, nevertheless, water
influxes may occur which, if associated with the presence of bacteria, can result in creation of
so called biogenic gas. From the chemical point of view shale gas is typically fairly clean and
dry, mainly composed of methane. This pure shale gas can be find only in the most thermally
mature shales, because they had enough heat and pressure, to produce it. However there are
formations that produce wet gas which may comprise some amounts of heavier hydrocarbons,
also in liquid physical state. Sometimes it is possible that shale gas can have small additions
of carbon dioxide or nitrogen, but this is more likely for biogenic gas [Frantz, Jochen, 2005].
13
4. Technology
4.1. Searching techniques
Since shale gas need particular conditions to be created it can occur only in areas with
appropriate geological settings. Hence crucial in searching for accumulations of shale gas is
geological knowledge about the region within which those accumulations are expected. It is
usually obtained through geophysical research including seismic imaging. In these days the
fast development of seismic imaging in three dimensions greatly changed the nature of shale
gas exploration. This technology creates a three-dimensional model of the subsurface layers
(fig. 11.). Sometimes even 4-D seismology is used. It adds time as a dimension, which allow
observation of how subsurface characteristics change with time. Scientists can now identify
shale gas prospects more easily. Specific recognition of geological conditions prevents
searching at random, thus it allows significant reduction of costs. Thanks to accurate
geological data scientists are able to designate the best spots to drill wells and know at what
depth the gas reservoirs lie [m]. This leads to both economic and environmental benefits.
Then, in order to confirm scientists interpretations, bore
holes are drilled. Advanced
technology allows to perform all essential geophysical methods which indicate properties of
reservoir rock as well as cap rock and other important elements. To find out the potential of a
reservoir, knowledge about content of total organic carbon within the rock is necessary.
Fig. 11. 3-D siesmic image [m]
With this information accurately determined the rock porosity and water saturation of the
reservoir is possible. To determine porosity which is the key parameter for both quantifying
14
the amount of free gas and estimating the permeability of the shale, an accurate rock density
is needed [Frantz, Jochen, 2005].
4.2. Drilling
A typical drilling method is the rotary drilling, where a roller-bit is attached to a drilling pipe
or string (fig. 12.). While rotating the drill string, the drill bit breaks into the earth and reaches
different depths, and eventually hits the targeted pay zone [Wang & Economides, 2009].
Earlier, to explore gas deposits, vertical drilling was performed. It is relatively cheap method,
however it is not efficient enough when used in case of shale gas deposits. Since gas
contained in shales cannot move freely within the rock and its accumulations are usually quite
thin but large in horizontal dimensions, that type of drilling does not penetrate the reservoir
layers effectively enough to be economically profitable. Starting in 1930s, as the technology
got improved, companies began drilling horizontal wells. In the past decades the horizontal
directional drilling industry has experienced exponential growth. Now this is very common
method of installation. The initial vertical portion of a horizontal well, unless very short, is
typically drilled using the same rotary drilling technique that is used to drill most vertical
wells.
Fig. 12. Scheme of the rilling rig [Wang & Economides, 2009]
15
In order to drill the curved part a hydraulic motor mounted directly above the bit is used. The
hole can be steered in a curve thanks to drilling forward without rotating the pipe. Typical
radius of curved section is around 90-150 m. In these days technology allows control of the
position of the drill bit all the time [Helms].
4.2.1. Drilling fluids
While drilling, cuttings created by the drill bit must be removed. This is done by pumping
mud through the drill pipe to the bit and backing up the annulus or space between the drill
pipe and the outer casing that is added as drilling proceeds. The mud is mixed with chemicals
and pumped down the drill pipe. The returning mud and rock cuttings that reach the surface
move by gravity down a return line to a shale shaker designed to separate the returning mud
from the rock cuttings for re-use. The remaining cuttings travel down a shale slide to a reserve
pit. Drilling fluids or mud are pumped down to provide hydraulic impact, control the pressure,
stabilize exposed formation, cool the drilling bit, prevent fluid loss, and bring the rock
cuttings to the surface [GWPC, 2009]. Drilling fluids are in liquid phase, but beside liquid
components they may comprise different solid additives as well. Two types of liquid drilling
fluids can be distinguish:

water-based fluids – the main phase may be either freshwater, seawater or brine and it
is mixed in appropriate proportions with chemical water-based liquids (fig. 13A.)

non-aqueous fluids – this type can be split into three groups based on their aromatic
hydrocarbon content:
- group I – high-aromatic content fluids
- group II – medium-aromatic content fluids
- group III – low/negligible-aromatic content fluids
Figure 13B shows general proportions of the liquid phase and chemical content of
non-aqueous fluid types. To choose the proper group several physical properties must
be considered with regard to technical, health, safety and environmental characteristics
[DFTF, 2009].
16
Fig. 13. General composition of A - water-based fluids, B - non-aqueous fluids [DFTF, 2009]
Drilling with compressed air is becoming an increasingly popular alternative to drilling with
fluids due to the increased cost savings from both reduction in mud costs and the shortened
drilling times as a result of air based drilling. The air, like drilling mud, functions to lubricate,
cool the bit, and remove cuttings. Air drilling is generally limited to low pressure formations
4.3. Fracturing
Hydraulic fracturing is a formation stimulation practice used to create additional permeability
in a producing formation, thus allowing gas to flow more readily toward the wellbore. This
process may be used to overcome both natural and resulting from drilling permeability
[GWPC, 2009]. The fracturing process is performed when the well is drilled. After this steel
pipe (casing) is inserted in the well bore. The casing is perforated within the target zone, so
that when the fracturing fluid is injected into the well it flows through the perforations into the
target zone. Finally, the reservoir rock will not be able to absorb the fluid as quickly as it is
being injected and the created pressure causes the rock to crack or fracture (fig. 14.). Once the
fractures have been created, injection stops and the fracturing fluids are flowing back to the
surface. Materials called proppants, which were injected as part of the fracturing fluid
mixture, remain in the target formation to hold the fractures open. Because of the length of the
laterals the fracturing process must be performed in stages. Fracturing is done of isolated
smaller portion of the lateral. The whole process begins from the furthest section and moves
uphole as each stage of treatment is completed. The main component of the fracturing fluids
is water and it reaches nearly 100 % of the whole content.
17
Fig. 14. Hydraulic fracturing process [n]
However several chemical additives are used and each serves a different purpose (table 2.).
The number of those additives depends on the conditions of the specific well [GWPC, 2009].
Table 2. Fracturing fluid additives and their purposes [GWPC, 2009]
Additive type
Diluted acid (15 %)
Biocide
Purpose
Help dissolve minerals and initiate cracks in the rock
Eliminates bacteria in the water that produce corrosive
byproducts
Breaker
Allows a delayed break down of the gel polymer chains
Corrosion inhibitor
Prevents the corrosion of the pipe
Crosslinker
Maintains fluid viscosity as temperature increases
Friction reducer
Minimizes friction between the fluid and the pipe
Gel
Thickens the water in order to suspend the sand
18
Iron control
Prevents precipitation of metal oxides
KCl
Creates a brine carrier fluid
Oxygen scavenger
pH adjusting agent
Removes oxygen from the water to protect the pipe from
corrosion
Maintains the effectiveness of other components, such as
crosslinkers
Proppant
Allows the fractures to remain open so the gas can escape
Scale inhibitor
Prevents scale deposits in the pipe
Surfactant
Used to increase the viscosity of the fracture fluid
19
5. Shale gas industry in the United States
For many years, natural gas companies have been producing the fuel from conventional gas
reservoirs, relatively close to the surface and easily accessible. New shale gas production
techniques have opened much wider areas for exploration. In recent decades the production of
natural gas from unconventional reservoirs in the United States has increased significantly.
Total shale gas resources in the this country have been estimated as more than 800 Tcf. Shale
gas production continues to increase. In 2009 it reached about 14 % of the total volume of dry
natural gas produced and about 12 % of the natural gas consumed (fig. 15.). The prediction
shows that by the year 2035 the sector of shale gas will constitute nearly half of the total
natural gas production.
Fig. 15. Present and future contribution of different natural gas source in United States [o]
Currently there are more than 35,000 producing shale-gas wells in the United States, with
cumulative production of about 600 Bcf per year. Obviously a so well established and still
developing industry affects many sectors, from economy to environment. There are a number
of issues that companies have to deal with to be allowed to proceed with this activity.
20
5.1. Major shale plays
Shale gas is present across much of the lower 48 States. There is several basins in the United
States that contained gas-rich shale formations (fig. 16.). In majority of those areas natural gas
was explored before from conventional reservoirs. Currently the major shale plays are:
Barnett Shale, Marcellus Shale, Fayetteville Shale, Haynesville Shale, Antrim Shale,
Woodford Shale, Eagle Ford Shale, Bakken Shale.
Fig. 16. Formations that comprise shale gas in the United States [Halliburton, 2008]
5.1.1. Barnett Shale
The Barnett Shale is a single, very large and continuous gas reservoir that is present across
Fort Worth Basin. It extends over an area of 28000 mi2 in north-east Texas and it is located
within the borders of 17 counties. It is a stratigraphic trap within a fault-bounded basin,
occupying a structural low and straddling the axis of the Fort Worth Basin. Most of the
Barnett production comes from a limited area in the northern part of the basin where the shale
is relatively thick. The play has expanded from the core area toward all directions, mostly to
the west and south.
The Fort Worth basin originates from the collision of two paleocontinents, Laurussia and
Gondwana, during the Ouachita Orogeny in late Paleozoic. Barnett Shale is mostly
Mississippian in age. It consists of dense, organic-rich, soft, thin-bedded, petroliferous,
21
fossiliferous shale and hard, black, finely crystalline, petroliferous, fossiliferous limestone. It
overlays Ordovician carbonate rocks which belong to Viola-Simpson formation and
Ellenburger Group (fig. 17.). The surface between them has an erosional character. Above
Barnett Shale lies the Pennsylvanian Marble Falls Formation comprising interbedded
limestone and shale and crystalline limestone. Partially in the eastern part the Marble Falls are
absent and Barnett Shale is overlaying by Pennsylvanian Bend Formation, consisting of
porous sandstone and conglomerate. In the northeastern part of the basin the Forestburg
Limestone Member divides Barnett Shale into two shale members. These members are
interbedded by limestone and dolomite and, in addition, the lower one can be subdivided into
five distinct shale units separated by limestone beds [Bruner, Smosna, 2011].
Fig. 17. North-south cross section through the Fort Worth Basin [Bruner, Smosna, 2011]
The Barnett Shale, is dominated by clay- and silt size sediments with occasional beds of
skeletal debris. Lithologically the formation consists of black siliceous shale, limestone, and
minor dolomite. The Barnett is a very good to excellent source rock in terms of its organic
richness. The organic content is generally highest in the silica-rich and phosphatic beds
(lowest in the dolomitic and calcitic beds), mostly in the lower shale member but also in the
upper Barnett. The average porosity in productive portions of the formation ranges from 3 to
6%, whereas porosity in nonproductive portions is as low as 1%. In the dry-gas window, gas
saturation equals 75%. Natural gas is stored within interstitial pores and microfractures and
adsorbed onto solid organic matter and kerogen [Bruner & Smosna, 2011].
22
5.1.2. Marcellus Shale
Just like the Barnett Shale, the Marcellus Shale is a very large and continuous gas reservoir. It
is a deep layer of rock that lies 1600 to 2700 meters underground, located in the Appalachian
Basin extending over 75000 mi2. It is present within the borders of seven states, however, the
core area, which has 50000 mi2 occurs in Pennsylvania, West Virginia and New York. It has
the best potential because the formation’s thickness exceeds there 15 m, hence exploration,
drilling and formation evaluation focus in these states.
The Appalachian basin has formed for over 200 mln years during three orogenies. Now it is
an asymmetrical basin with its structural axis directed northeast-southwest at the depth of
1800 m b. s. l. The Marcellus Shale belongs to the Hamilton Group and is Middle Devonian
(Eifelian and Givetian) in age. It is a splintery, soft to moderately soft, gray to brownish black
to black, carbonaceous, highly radioactive shale with beds of limestone and carbonate
concretions. The formation in the thickest place exceeds 200 m in the northeast and it is
continuously thinning in the southwest direction (fig. 18.) [Bruner & Smosna, 2011].
Fig. 18. Stratigraphic west-east cross section through the appalachian basin [Bruner & Smosna, 2011]
The Marcellus is divided into three formal members. The lower one is thinly bedded, organicrich, pyritiferous, blackish gray to black shale with lime-mudstone concretions. Interbeds of
siltstone occur at its base. The middle member is a skeletal, fine-grained limestone or an
interbedding of limestone and calcitic shale. The upper member comprises two units: a basal
black shale resembling the lower member and an upper unit of gray shale. Directly below the
23
Marcellus lie Lower Devonian formations comprising Onondaga Limestone, Huntersville
Chert, and Needmore Shale. The Marcellus is overlaid by the Mahantango Formation, the
upper unit of the Hamilton Group. It contains a variable mix of mudstone, limestone,
sandstone, and conglomerate. The Mahantango Formation in turn lies below the well bedded,
fossiliferous, argillaceous, and pyritiferous micritic limestone and limey shale Tully
Limestone. The total organic carbon (TOC) content of the Marcellus changes rapidly from
place to place and from layer to layer. TOC both in the lower and upper Marcellus members
varies from 2–4% in some parts of the basin, up to 4–6% elsewhere. The source-rock
potential of the both lower and upper Marcellus members is considered as exceptional to
excellent, depending on the location. Two sets of natural fractures were identified in the
Marcellus: one striking northeast and the other striking northwest. Fracturing was attributed to
local and regional tectonic stresses, uplift and erosion of the stratigraphic overburden, and
mechanical compaction of the rocks. Porosity has two components—interparticle (or matrix
porosity located between silt and clay
articles and organic matter) and open fractures.
Average porosity has values around 6% to 10%. Gas saturation varies between 55–80% while
water saturation, between 20–45%. The production of formation water is nil, suggesting that
the shale has no free water or that the relative permeability for water is zero [Bruner, Smosna,
2011].
5.1.3. Fayetteville Shale
The Fayetteville Shale is present across the Arkoma Basin and produces natural gas in its
central portion. It extends over 4000 mi2 and underlies much of northern Arkansas and
adjacent states. The productive wells penetrate the Fayetteville Shale at depths between a few
hundred and 2100 m below the surface. The thickness of the Fayetteville varies from 15 m in
the western Arkansas to 150 m in the eastern Arkansas. Three productive formations can be
distinguished: Hale Sand, Fayettville and Moorefield. The Fayettville Formation can be
divided into two subunits, the lower, which is usually a target zone, and the upper. The
Fayettville is a Mississippian, organic-rich rock consisting of black and pyritic shale, with
subordinate amounts of interbedded, siliceous chert and siltstone. The exploration target is
very mature because of tectonic and igneous events and contain only dry gas consisting
almost exclusively of pure methane (98 %).
24
5.1.4. Haynesville Shale
The Haynesville Shale underlies large parts of southwestern Arkansas, northwest Louisiana,
and East Texas at depths between 3100 to 3900 m below the surface. The Haynesville Shale
has a lateral extent of about 9000 mi2. The average layer thickness is about 60 to 90 m. The
Haynesville Formation was created during Kimmeridgian and Tithonian, stages of the Upper
Jurassic, between 145 and 156 mln years ago. The Haynesville Shale overlies limestone of the
Smackover Formation and is overlaid by the sandstone of the Cotton Valley Group. It may, in
some parts, laterally go into the Haynesville Lime of the same age and vertically into the
younger Bossier Shale. Haynesville is a black, organic-rich shale which, due to its low
permeability, was originally considered to be a gas source rock rather than a gas reservoir.
This formation is characterized by low average porosity, which is less than 8 %. It is well
saturated by gas, but has a quite low recovery factor. Because the formation sealing it has
high pore pressure.
5.1.5. Bakken Shale
The Bakken Formation is a thin but widespread unit within the central and deeper portions of
the Williston Basin in Montana, North Dakota, and the Canadian Provinces of Saskatchewan
and Manitoba. It is Upper Devonian-Lower Mississippian in age and overlies the Upper
Devonian Three Forks Formation and underlies the Lower Mississippian Lodgepole
Formation. It ranges in thickness from zero to 30 m, however, in places where salt collapse
structures have formed it may be more than 70 m thick. The formation consists of three
members: lower and upper shale members separated by middle sandstone member. Each
succeeding member is of greater geographic extent than the underlying member. Lower and
upper Bakken shales are black, organic-rich clay beds of quite consistent lithology. Beside
clay they comprise also quartz, dolomite, and pyrite. They are the petroleum source rocks and
part of the continuous reservoir for hydrocarbons produced from the Bakken Formation. The
lithology of the middle member is highly variable and consists of a light-gray to mediumdark-gray, interbedded sequence of siltstones and sandstones with lesser amounts of shale,
dolostones, and limestones rich in silt, sand, and oolites. It varies also in thickness, and
petrophysical properties. Total organic carbon within the shales may be as high as 40%.
Multiple fracture types occur on a macroscopic and microscopic scale in the Bakken
25
Formation and are most abundant in the lower and middle members. Fractures in the lower
member typically are open bedding plane, or open hair-like vertical features. Irregular and
blocky or smooth and conchoidal fractures are common in the more siliceous shales. One or
more of these fractures may be healed with calcite or pyrite [Pitman et al., 2001; Terneus,
2010].
5.2. Laws and regulations
There is a complex set of federal, state and local laws that regulates development and
production of oil and gas, including shale gas. They apply to both conventional and
unconventional resources as well. There are agencies that administer exploration and
production on each level. Many of the federal laws are implemented by the states under
agreements and plans approved by the appropriate federal agencies.
5.2.1. Federal laws
Several federal laws regulate most of environmental aspects of shale gas development.
However, federal agencies do not have the resources to administer all of these environmental
programs for all the oil and gas sites around the country. Moreover, one set of national
regulations may not always be the best way of assuring a high level of environmental
protection. In practice it works in the way that states implement the programs with federal
oversight. The important thing is that states may adopt their own standards, however, these
must be at least as protective as the federal standards they replace.
5.2.2. State laws
State laws of the environmental activities related to shale gas development may more
efficiently regulate the exploration and production depending on the given regional character
and properties. The regional specifications usually include environmental as well as social
aspects. It might be geology, climate, topography, industry, population density and/or local
economics. It is common that several agencies have jurisdiction over different activities.
Except implementation of federal laws, states may create their own rules and standards, which
are often even more rigorous than the national ones. The states’ governments have broad
26
powers to permit and enforce all activities, including drilling of the wells, production
operations, management and disposal of the wastes.
5.2.3. Local laws
Local authorities can make additional requirements and regulations regarding the oil and gas
industry. All entities such as cities, counties, tribes and regional water authorities have the
right to add extra demands to existing laws. In cases, when activities take place in or near
populated areas, local governments may establish ordinances to protect the environment and
the general welfare of its citizens. Sometimes regional water-permitting authorities are
established. They have jurisdiction across several states and theirs main goal is to protect the
water quality of the entire river basin and to govern uses of the water.
5.2.4. Clean Water Act (CWA)
The CWA was established in order to protect water quality and it is the primary federal law
governing pollution of surface water. It comprises regulation of pollutant limits on the
discharge of oil- and gas-related produced water. CWA include pollution control programs
such as setting wastewater standards for industry and water quality standards for different
contaminants in surface waters. It made it unlawful to discharge any pollutant from a point
source into the navigable waters without specific approved permit. The National Pollutant
Discharge Elimination System (NPDES) permit program controls discharges from point
sources that are discrete conveyances, such as pipes or man-made ditches. This applies to
industrial, municipal and other facilities such as shale gas production sites or commercial
facilities that handle the disposal or treatment of shale gas produced water. To keep the
effluent concentration in the specific surface water body under the maximum allowable level,
NPDES permits must include for example technology-based effluents limits, which are based
on available treatment technologies. Before the proper agency grants a permit, the potential
impact of each proposed surface water discharge on the quality of the receiving water must be
considered.
27
5.2.5. Safe Drinking Water Act (SDWA)
The main purpose of the SDWA is protection of public health by regulating the nation’s
public drinking water supply. The Underground Injection Control (UIC) program was
established in order to prevent the injection of liquid wastes into underground sources of
drinking water (USDW) . It sets standards for safe waste injection practices and forbid certain
types of injection altogether so that injection wells do not endanger USDW. The injection
wells are divided into five categories:

Class I – wells may inject hazardous and non-hazardous fluids into isolated
formations beneath lowermost USDW,

Class II – wells may inject brines and other fluids associated with oil and gas
production,

Class III – wells may inject fluids associated with solution mining of minerals,

Class IV – wells may inject hazardous or radioactive wastes into or above a
USDW and are banned unless specifically authorized under other statutes for
ground water remediation,

Class V – in general these wells inject non-hazardous fluids into or above a
USDW and are on-site disposal systems.
There has been proposed also Class VI, which would be comprise the CO2 injection wells for
the purpose of sequestration. The majority of wells used in gas production belongs to Class II.
They might be used to inject fluids into oil- and gas-bearing zones to increase recovery or
disposed of produced water. USDWs are under particular protection in the way, that the law
allows to inject the waste fluids only to formations that are not USDWs. All injection wells
require authorization under general rules or specific permits.
5.2.6. Clean Air Act (CAA)
The CAA is the basic law that regulates potential emissions that could affect air quality and
set national standards to limit levels of certain pollutants. Basically, air regulations concern all
subjects in the same way, regardless the company’s size, the age of a field and the type of
operation. Moreover, they do not distinguish between conventional and unconventional plays
or old fields between new ones. Generally the air emissions regulations are the same for the
shale plays as for any other natural gas operations. The only differences may occur
28
considering location, equipment needs or sulfur content level of the gas. Areas that do not
fulfill the CAA standards for any pollutant are designated as “nonattainment areas”, and
activities within those areas must follow much more rigorous regulations than the same
activities outside of them. Implementation of the CAA caused improvement of the air quality
across United States during the last decades. The National Emission Standards for Hazardous
Air Pollutants (NESHAPs) was established in order to control specific air emissions and
Maximum Achievable Control Technology (MACT) standard was implemented. It relates to
hazardous air pollutants that concern for example shale gas operations located in areas near
larger populations. The facility owners and operators must have the air permit to be allowed
to carry on their business. These permits clarify all issues associated with gas production in
the particular type of allowed constructions, emissions limits or the way that the emission
source must be operated.
5.2.7. Resource Conservation and Recovery Act (RCRA)
The main purpose of the RCRA is to protect human health and the environment against the
industry wastes. It regulates hazardous wastes management from their creation to destruction
or storage in order to make sure that they cannot endanger human health. Because some
industries, including the shale gas
industry, produce wastes of lower toxicity, the
requirements for them have been reduced. In consequence drilling fluids, produced waters and
other wastes associated with all stages of crude oil, natural gas and geothermal energy became
exempt from RCRA by Solid Waste Disposal Act (SWDA).
5.2.8. Endangered Species Act (ESA)
In order to protect animals and plants that are considered as endangered or threatened, the
ESA was passed. It forbids to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture,
collect a plant or animal or significantly change their habitats regardless that they are located
on private property. Before starting the activity, the owner or operator must check whether
permit are necessary or not by contacting the proper biological survey. Permit, if needed,
must include a habitat conservation plan comprising for example: an assessment of impact
and measures that will be undertaken to monitor, minimize and mitigate any impacts.
29
5.2.9. Occupational Safety and Health Act (OSHA)
The OSHA contain regulations that require formal employers to make a workplace safe and a
healthy place for the employees. It encourages employers to provide trainings, outreach and
education, employ standards that reduce potential safety and health hazards in the oil and gas
industry.
30
6. Environmental concerns
The primary concerns are to do with potential risks posed to different aspects of water
resources, but also atmosphere contamination and other:
6.1. Risk of shallow freshwater aquifer contamination, with fracture fluids
The protection of freshwater aquifers from fracture fluids has been a primary objective of oil
and gas field regulation for many years. There is substantial vertical separation between the
freshwater aquifers and the fracture zones in the major shale plays. The shallow layers are
protected from injected fluid by a number of layers of casing and cement and as a practical
matter fracturing operations cannot proceed if these layers of protection are not fully
functional. Despite these protections shale gas extraction poses serious risks of contamination
of groundwater by either the fracturing fluid or by methane. This can happen either through
cracks in the well, or via natural fissures in the rock or fractures created by the fracturing
process. It is estimated that 20-85% of fracturing fluid remains underground.
There is
considerable evidence of problems with methane for people living close to shale gas wells. In
extreme situations they are able to set light to their tap water. A recent research found
methane levels in shallow drinking water wells were 17 times higher near active gas drilling
areas than elsewhere. Contamination with fracturing fluid is potentially more harmful to
human health because of the nature of the chemicals used [Friends of Earth, 2011].
6.2. Risk of surface water contamination, from inadequate disposal of fluids
returned to the surface from fracturing operations
The fracturing fluids are injected into the geological formations at high pressure. Once the
pressure is released, a mixture of fracturing fluid, methane, compounds and additional water
from the deposit flow back to the surface. Approximately between 20% and 50% of the water
used for fracturing gas wells returns to the surface as flowback. Part of this water will be
recycled to fracture future wells. This water must be collected and properly disposed of. The
effective disposal of fracturing fluids may represent much of a challenge, particularly away
from established oil and gas areas, although again it must be put into the context of routine oil
31
field operations. Every year the onshore United States industry disposes of around 18 billion
barrels of produced water. By comparison, a high volume shale fracturing operation may
return around 50 thousand barrels of fracture fluid and formation water to the surface. The
challenge is that these relatively small volumes are concentrated in time and space. The main
problem is the huge amount of waste water and the improper configuration of sewage plants.
Recycling might be one of the possible solutions, but this may increase total costs of the
project. This is the reason why some companies try to avoid increasing the project costs by
unlawful activities. Several of those illegal operations have been reported, including for
example: disposal of fracturing flowback fluid into a wetland and a tributaries of river system,
discharge diesel fuel and fracturing fluids into the ground, improper implementation of
erosion and sedimentation control measures leading to turbid discharges, fracturing fluid
overflow from a wastewater pit contaminating a high-quality watershed [Lechtenböhmer et al.
2011].
6.3. Risk of surface and local community disturbance, due to drilling and
fracturing activities
Thanks to the development of technology, present drilling sites occupy a much smaller area
than several years back in time. The horizontal drilling allows in addition to constrain the
number of drilling wells without limiting the exploration area. Despite this, it still requires a
lot of space to develop production site, and plenty of those sites are necessary to fully exploit
the reservoir. Another disturbance is that, regardless of whether the water is transported to a
disposal or treatment facility, there is going to be a lot of traffic for a short period of time.
Water or waste haulers are going to be using county and local roads, and sharing space with
normal traffic. This is not only disruptive to the local community, but it can also be
destructive to the roads. This has become a problem for at least few counties that are dealing
with shale truck traffic [Lechtenböhmer et al. 2011].
6.4. Risk of atmosphere contamination
Natural gas possesses remarkable qualities. Among the fossil fuels, it has the lowest carbon
intensity, emitting less carbon dioxide per unit of energy generated than other fossil fuels. It
32
burns cleanly and efficiently, with very few non-carbon emissions. Unlike oil, gas generally
requires limited processing to prepare it for end-use. However, there are evidences of higher
levels of air pollution near gas wells, and of associated health problems. In some regions,
levels of benzene near shale gas wells have been found to be more than five times permitted
levels. Emissions from shale gas wells can also cause photochemical smog – levels of ozone
in one of the counties in Wyoming where there is a high concentration of gas wells have been
recorded as higher than in Los Angeles. The evidence of health impacts is for example that in
six counties in Texas near drilling sites the asthma rates have been reported as three times
higher than the state average. The emissions potentially originate from the following sources:
emissions from trucks and drilling equipment, emissions from natural gas processing and
transportation, evaporative emissions of chemicals from waste water ponds, emissions due to
spills and well blow outs (dispersion of drilling or fracturing fluids combined with
particulates from the deposit). The mainly emitted gases are sulfur dioxide, nitrogen oxides,
carbon oxides and non-methane volatile organic compounds (NMVOC). The operation of
drilling equipment consumes large amounts of fuels which are burnt to emit CO2. Also, some
fugitive emissions of methane might occur during production, processing and transport
[Friends of Earth, 2011].
6.5. Earthquakes
It is well known that hydraulic fracturing can induce small earthquakes in the order of 1-3 at
the Richter scale. In the United States the rate of small earthquakes has increased over the last
years significantly. Concerns rose that these are induced by the steep increase in drilling
activities in the shale basins. Some regions has experienced small earthquakes first times for
more than a hundred years [Lechtenböhmer et al. 2011].
33
7. Shale gas in Europe
The scale of the possibility of industry exploration and production of unconventional natural
gas, observed in North America, has resulted in attempts to transfer these experiences to other
continents. Europe is one of the most active exploration areas in the world of unconventional
hydrocarbon deposits (fig. 19.), although identification of individual basins is still at an early
stage. An important area of research is the Lower Saxony Basin in northwestern Germany,
potentially containing deposits of natural gas in Lower Jurassic shales in which first holes
have been drilled. Drilling is currently underway in Skåne (southern Sweden), where natural
gas is searched in the Upper Cambrian shales. Despite the interesting geochemical parameters
of the basin, its spatial scale is small, which means that the potential resources are not as large
as expected in Poland. Other basins in Europe at the present level of diagnosis are in terms of
possibilities for natural gas in shale less promising (fig. 19.). In the Vienna Basin an
interesting Jurassic shale formation has been found. However, it occurs at depths of up to
8000 m, which makes the exploitation of gas uneconomic. In England gas exploration is
conducted in the Carboniferous shales in the central part of the country and in the Lower
Cretaceous Wealden shales in south-east England. In both regions, prospects for discoveries
the gas fields are, for various reasons, rather limited and the extent of the variant prospects
relatively small. In south-western Germany, the object of research are Carboniferous-Permian
shales in the Bodensee trough in the base of the Alpine Hollow Basin. In the south,
exploration works are conducted within the Mako trough in Pannonian basin, where there is a
mixed system of tight gas and shale gas, and the tight gas is more important element. Strong
interest in companies looking for natural gas in shales is currently focused on France. The
main basin, analyzed in this regard, is the South-West Basin of the Lower Jurassic and the
Upper Cretaceous shales. This Basin, however, is still poorly understood. In recent years, the
Parisian Basin has been studied intensively, but it turned out that the Lower Jurassic shales
that occur there have too low thermal maturity to be able to produce natural gas. Currently, in
this basin, the extracting oil from shale is the mainly considered possibility. On this
background Poland is one of the most attractive shale gas exploration areas in Europe. The
biggest prospects for gas production is found in the Lower Paleozoic shales in the East
European Craton (EEC) - in the Baltic Basin, Podlasie Depression and Lublin region. Except
for the shale formations in Poland, Sweden, Hungary and Germany, direct exploration is not
carried out in the other basins of Europe [Poprawa, 2010a].
34
Fig. 19. Localization of the main European sedimentary basins, within which shale gas might occur (red –
basins with current shale gas exploration, orange – basins considered for shale gas exploration)
[Poprawa, 2010a]
7.1. Shale gas in Poland
In the past few years in Poland there has been an increasing interest in exploration and
production prospects for unconventional gas accumulations. It is due to the possibility of
applying new technologies including horizontal drilling and technical procedures involving
hydraulic fracturing, and the ability to perform a large number of drillings in a short time. The
35
economic considerations also play an important role, such as expected increases in energy
prices. Referring to data from 1 March 2010 in Poland, 210 concessions were granted for
prospecting and exploration of crude oil and natural gas (fig. 20.). This number includes
concessions to search for both conventional as well as unconventional hydrocarbon resources.
At this stage it is impossible to estimate the size of the unconventional natural gas deposits in
Poland. The size of these reservoirs will be determined by the results of work performed
under the given license. Permits for prospecting and exploration of shale gas have been issued
in 2007-2010. The range of work established by companies owning this type of concessions
in the first place include an analysis of archival data and their interpretation, then the field
seismic imaging and, based on their results, performance of exploration drilling
[Zalewska, 2010].
Fig. 20. Map showing the concessions for prospecting and exploration conventional and unconventional
hydrocarbons resources (red – concessions for shale gas exploration from the Lower Paleozoic shale,
brown – concessions for unconventional gas exploration from the other formations, grey – concessions for
conventional hydrocarbon exploration) [Zalewska, 2010]
36
7.1.1. Geological conditions
Shales enriched in organic matter were deposited in the system of sedimentary basins
developed in the early Paleozoic on the western slope of the EEC. As a result of the
subsequent tectonic processes and erosion these basins have been divided into the Baltic
Basin, Podlasie Depression and Lublin region (fig. 21.).
Fig. 21. Localization of Lower Paleozoic sedimentary basins and areas of Upper Ordovician and Lower
Silurian shales occurrence [Poprawa, 2010b]
37
The individual Lower Paleozoic basins on the western EEC slope have similar facial
development (fig. 22.). So far they have been objects of conventional hydrocarbon
exploration, discovered and exploited only in the northern part of the Baltic Basin.
Their characteristic feature is their relatively simple tectonic structure, which favors
exploration of shale gas. The major feature of the Baltic Basin and the Podlasie Depression is
their deflection toward the west and south-west. Typical for these areas is also a small number
of faults, which tend to have small displacements. These features can be considered beneficial
for gas production from shale. The quite simple structural arrangement of the complex of
Lower Paleozoic shales can maintain a long section of horizontal drilling within the
formation. The Lublin Region has a slightly more complicated tectonic structure. The
structural system of Lower Paleozoic formations is complicated by block tectonics,
developing from the end of the Famennian to early Visean. These evolved into a system of
tectonic blocks limited by fault zones, undergoing heterogeneous upwards movement and
erosion. However, , the degree of tectonic deformation and fault involvement may vary within
individual blocks [Poprawa, 2010b].
The distinctive element of the Lower Paleozoic sediments profile for EEC occur over large
areas. The dark clayey-mud deposits, enriched in organic matter, contain potential
accumulations of natural gas. These are mainly graptolite shales of Upper Ordovician and
Lower Silurian age and, in much lesser extent, Ludlow age. The development of this type of
sedimentation was the result of the impact of numerous factors, among others.: subsidence of
the basin, reservoir bathymetry, its
organic productivity, geochemical conditions in the
bottom zone, the presence of barriers in the bottom topography and configuration of ocean
currents and climate conditions. From the perspective of exploration, a high content of silica
is preferred in the shales. This determines the rock susceptibility to fracturing, which in turn
determines the possible flow of gas into the borehole. Lower Paleozoic shales in this regard
are relatively poorly studied, although the few available data indicate that the silica content in
these sediments is high [Poprawa, 2010b].
The principal geological and geochemical parameters of the lower Paleozoic shales favouring
the accumulation of natural gas are: the thickness of intervals rich in organic matter, organic
matter contents, thermal maturity and depth of shale deposition. A significant variation in the
value of each of these parameters in the lid of the western slope of EEC, as well as their
38
complex interactions make the potential occurrence of gas accumulation in the Lower
Paleozoic shales variable and hard to determine.
Fig. 22. Lithostratigraphic section of the Lower Paleozoic in the Lublin Region and Baltic Basin
[Poprawa, 2010b]
39
In the eastern part of the Podlasie Depression, as well as in the eastern part of the Baltic
Basin, the rocks presently lying at relatively small depths, down to 1000-2000 m, had a high
content of organic matter, locally up to 15-20%. Considering that the thermal maturity of
these rocks reaches 0,8-1,1% Ro, accumulations of oil shale can be expected. Thermal
maturity of the Lower Paleozoic shales increases westward. Although in areas where it is
contained in the 1.1-1.3% Ro, difficulties in the production of gas from shales may occur
because of the relatively high contents of hydrocarbon gases heavier than methane. Possible
co-occurrence of crude oil with natural gas in shales may pose further problems. In the
western parts of the basins on the EEC slope, where the Lower Paleozoic shales have very
high thermal maturity, the samples that were obtained from the conventional reservoirs of
Cambrian and Lower Ordovician age, indicate the presence of dry gas. In the zone of high
potential exploration are relatively thick shale intervals of average contents of organic matter
in excess of 1-2% TOC and thermal maturity proper to generate natural gas. The reservoir
analysis indicate that these shales could possibly comprise a good quality dry gas with low
nitrogen contents. The depth of the shale can provide economically reasonable exploration
targets for natural gas. Similar Upper Ordovician and Lower Silurian shales are present also
in the Małopolska Block. The potential occurrence of these natural gas accumulations,
however, is smaller than on the EEC, as a result of intense erosion, they are preserved only as
isolated patches. In addition, the individual profiles of the Upper Ordovician and Lower
Silurian Małopolska Block contain more hiatuses than the EEC and have lower contents of
organic matter. Moreover, large areas of the Lower Paleozoic shales of the Małopolska Block
are not thermally mature enough to generate natural gas. The advantage of the western part of
the Lower Palaeozoic shales of EEC is their large lateral spread. Also the relatively simple
tectonic structure of this area, especially in the Baltic Basin and the Podlasie Depression
favors the exploration of natural gas from shales. The relatively low density of faults
facilitates the fracturing and imposes no risk of takeover by the faults fracture systems
[Poprawa, 2010b].
7.1.2. Risks and problems
Although occurring in the Polish part of the EEC, the Lower Paleozoic shales are a major
concern in the oil industry and in the coming years in their exploration for natural gas.
Although huge financial resources will be invested, it should be emphasized that some
geological regulatory conditions suggest an increased risk of exploration. Compared to
40
conventional gas-bearing shale formations in the world, such as the Barnett Shale in the
United States, the Lower Paleozoic shales in Poland are characterized by a slightly lower
average content of organic matter. From the viewpoint of organic geochemistry it is also
important that they are older than the gas-bearing shales in the best recognized basins.
Moreover, in these zones of the EEC, in which the Lower Paleozoic shales are present today
to a depth of 3000-3500 m the degree of thermal maturity is lower than in the Barnett Shale.
A typical feature of the basins containing deposits of natural gas in shales is also the presence
of conventional natural gas or crude oil, because the gas-bearing shales formations are also
high quality source rocks for conventional natural gas. In the Polish part of the western slope
of EEC, attention must be paid to that the conventional hydrocarbon deposits are small and
few. Lack of conventional hydrocarbon reservoirs within the Lower Paleozoic complex can be
partly explained by lack of reservoir formations in the overburden of Upper Ordovician and
Lower Silurian shales. The second reason for the lack of conventional hydrocarbon deposits
in this area may be the very poor reservoir properties of Cambrian rocks, related primarily to
their cementation. In a number of holes on the EEC, symptoms of natural gas in Silurian rocks
were reported. However, the amount and intensity of those symptoms is relatively small
compared to the symptoms found in the classic basins with gas-bearing shales. Occurrence of
overpressure within shales favors effective production of natural gas from such rocks. So far,
within the Lower Paleozoic shales of EEC, reservoir tests were not performed, so the gas
pressures in these complexes are poorly known. However, during drilling of the Ordovician
and Silurian rocks, the impact of overpressure on the drilling fluid was not recorded. Also in
better known Cambrian rocks below the shales, there was no significant overpressure. The
other element of economic risk of exploration are also indications of increased nitrogen
contents in conventional reservoir rocks especially in the eastern part of the basin. The
genesis of nitrogen, as well as its relationship to Lower Paleozoic shales, however, remain at
this stage of diagnosis unclear [Poprawa, 2010b].
Exploration of shale gas in Poland is only just beginning. Operators of concessions are at the
stage of data analysis or preparation for drilling boreholes. In fact, only the analysis of the
first wells can give a preliminary answer to the question about the real potential of
Ordovician-Silurian shale gas formations. The successful development of shale gas could
become a breakthrough in providing energy security for the Poland. Due to the experience
and technological advancement the American companies have the greatest chance of success
in shale gas exploration. However, risk-taking companies, that invest large funds in search of
41
shale gas can encounter several problems. Firstly, the domestic protectionism of service
companies (especially drilling ones), which consists of regulations hindering the involvement
of foreign drilling companies and the lengthy and troublesome procedures for importing
drilling equipment from outside the European Union. Another problem is the need to organize
tenders for performance of drilling. An important obstacle may be changing regulations and
uncertainties in their interpretation concerning the rights to geological information and the
high price of this information. This also pertains to frequent changes and unclear regulations
relating to environmental protection, in particular those concerning environmental impact
assessments that do not take into account the specifics of oil exploration. Another obstacle
may be uncertainty about the price of gas resulting from insufficient liberalization of the
domestic gas market [Hadro, 2010].
42
8. Conclusions
Unconventional natural gas deposits are treated as a supplement to declining conventional gas
deposits. Although great geological resources, they are still more difficult for industrial use
than conventional deposits. Thanks to advanced technology of horizontal drilling and
hydraulic fracturing, the shale gas are increasingly of great importance in the United States.
However, the very different operating conditions of shale gas and sensitivity to price
fluctuations generally require a much more cautious approach to investing than in the case of
conventional deposits. Prevalence of shale gas in almost all the sedimentary basins of the
United States where conventional hydrocarbons are present, indicates the possibility of the
occurrence of these deposits also outside the United States. However, complex reservoir
conditions and the need to use advanced techniques for requires the integration of many fields
of science and experience of the oil industry. The current exploration of shale gas in Poland
was initiated mainly by American companies. A weak geological data base of the Ordovician
– Silurian shales, which are the target of exploration involves a high risk of exploration. This
demands very careful business planning. The proposed geological works are spread over
several steps to minimize investment risk. An important element of the strategy of shale gas
exploration is to obtain the greatest possible concession area, which creates the future
possibility of identifying the most promising areas. If the development of shale gas would be
successful, then Poland faces a great opportunity for independence from imported gas. There
is an understandable optimism and enthusiasm that accompanies this start of shale gas
exploration. However, one must pay attention to the challenges and barriers that may stand in
the way of exploration success. Key challenges include the transfer of technology from the
United States, associated with the expansion of the base for drilling services and sharing gas
fields. Another problem may be restrictions associated with the availability of locations for
drilling which are much greater than in the United States, when concerning population density
and presence of environmentally sensitive areas. Potential barriers of exploration arise from
protectionism of the domestic market of service companies, variability and uncertainty of the
legislation and insufficient gas market liberalization. In this situation, the Polish government
must play an active role in removing these barriers and create optimal conditions for
investment, for example, develop a system of financial incentives for potential investors in
extracting unconventional gas.
43
9. Acknowledgements
I would like to thank Ass. Professor Lennart Bjӧrklund for his willingness to share his great
experience and his substantial help in the creation of this paper.
44
10. Figures and tables
Fig. 1. Scheme of hydrocarbons reservoir creation
Fig. 2. Different types of structural traps
Fig. 3. Evolution of kerogen
Fig. 4. Zones of natural gas and oil creation
Fig. 5. Scheme of installation for natural gas use
Fig. 6. A typical geological formations in which natural gas could be find in association with
crude oil
Fig. 7. Resources of conventional and unconventional gas
Fig. 8. Visualization of trapped gas (blue) in unconventional (left) and conventional (right)
reservoir rock
Fig. 9. Methane molecules trapped inside the water molecules cages
Fig. 10. Macroscopic (left) and microscopic (right) view of shale rock
Fig. 11. 3-D siesmic image
Fig. 12. Scheme of the rilling rig
Fig. 13. General composition of A - water-based fluids, B - non-aqueous fluids
Fig. 14. Hydraulic fracturing process
Fig. 15. Present and future contribution of different natural gas source in United States
Fig. 16. Formations that comprise shale gas in the United States
Fig. 17. North-south cross section through the Fort Worth Basin
Fig. 18. Stratigraphic west-east cross section through the appalachian basin
Fig. 19. Localization of the main European sedimentary basins, within which shale gas might
occur
Fig. 20. Map showing the concessions for searching and exploration conventional and
unconventional hydrocarbons resources
Fig. 21. Localization of Lower Paleozoic sedimentary basins and areas of Upper Ordovician
and Lower Silurian shales occurrence
Fig. 22. Lithostratigraphic section of the Lower Paleozoic in the Lublin Region
and Baltic Basin
Table 1. Typical composition of natural gas
Table 2. Fracturing fluid additives and their purposes
45
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