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.

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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.

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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]

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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]

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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].

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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

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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.

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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.

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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.).

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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]

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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]

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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]

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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].

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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

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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]

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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].

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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.

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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

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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

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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.

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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,

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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].

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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 %).

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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

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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

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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.

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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

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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.

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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.

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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

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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].

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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].

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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]

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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]

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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]

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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

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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].

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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.

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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.

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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

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11. References Bruner, K. R., Smosna R., 2011: A Comparative Study of the Mississippian Barnett Shale, Forth Worth Basin, and Devonian Marcellus Shale, Appalachian Basin. U. S. Department of Energy, National Energy Technology Laboratory Drilling Fluids Task Force, 2009: Drilling fluids and health risk management. A guide for drilling personnel, managers and health professionals in the oil and gas industry. OGP Report Number 396, International Petroleum Industry Environmental Conservation Association, International Association of Oil & Gas Producers Frantz, J. H., Jochen, V., 2005: Shale Gas. White Paper, Schlumbergere Friends of Earth, 2011: Shale gas: energy solution or fracking hell?. Ground Water Protection Council, 2009: Modern Shale Gas Development in the United States: A Primer. U. S. Department of Energy, National Energy Technology Laboratory, Office of Fossil Energy Hadro, J., 2010: Strategia poszukiwań złóż gazu ziemnego w łupkach. Przegląd Geologiczny, vol. 58, nr 3, Halliburton, 2008: U.S. Shale Gas. An Unconventional Resource. Unconventional Challenge. White Paper Hammes, U., Hamlin, H. S., Ewing, T. E., 2011: Geologic analysis of the Upper Jurassic Haynesville Shale in east Texas and west Luisiana. AAPG Bulletin, Vol. 95, No. 10 Helms, L.: Horizontal Drilling. DMR Newsletter, Vol. 35, No. 1 Holditch, S. A., 2007: Unconventional gas. Working Document of the NPC Global Oil & Gas Study Lechtenbӧhmer, S., Altmann, M., Capito, S., Marta, Z., Weindrorf, W., Zittel, W., 2011: Impacts of shale gas and shale oil extraction on the environment and on human health. Study. Directorate General for Internal Policies, Policy Department A: Economic and Scientific Policy, Environment, Public Health and Food Safety

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Magoon, L. B., Beaumont, E. A., 2003: Petroleum system. Monize, E. J., Jacoby, H. D., Meggs, A. J. M., 2010: The Future of Natural Gas. An interdisciplinary MIT Study. MIT Energy Initiative Pitman, J. K., Price, L. C., Lefever, J. A., 2001: Diagenesis and Fracture Development in the Bakken Formation, Williston Basin: Implications for Reservoir Quality in the Middle Member. U.S. Geological Survey Professional Paper 1653 Poprawa, P., 2010a: System węglowodorowy z gazem ziemnym w łupkach – północnoamerykańskie doświadczenia i europejskie perspektywy. Przegląd Geologiczny, vol. 58, nr 3, Poprawa, P., 2010b: Potencjał występowania złóż gazu ziemnego w łupkach dolnego paleozoiku w basenie bałtyckim i lubelsko-podlaskim. Przegląd Geologiczny, vol. 58, nr 3, Stupnicka, E., 1997: Geologia regionalna Polski. Wydawnictwa Uniwersytetu Warszawskiego, Warszawa Terneus, J., 2010: Final Report. Subtask 1.2 – evaluation of key factors affecting successful oil production in the Bakken Formation, North Dakota. U. S. Department of Energy, National Energy Technology Laboratory, Office of Fossil Energy Wang, X., Economides, M., 2009: Advanced Natural Gas Engineering. Gulf Publishing Company, Houston, Texas Zalewska, E., 2010: Koncesje na poszukiwanie i rozpoznawanie złóż węglowodorów w Polsce w tym shale gas i tight gas. Przegląd Geologiczny, vol. 58, nr 3,

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Websites accessed 28.11.2011 [a] http://www.gasproductiontech.com accessed 29.11.2011 [b] http://www.glossary.oilfield.slb.com/Display.cfm?Term=kerogen [c] http://www.alfonsussimalango.blogspot.com accessed 30.11.2011 [d] http://www.naturalgas.org/overview/background.asp [e] http://www.oilandgasgeology.com [f] http://www.cowpattypatty.com accessed 01.12.2011 [g] http://www.capp.ca/canadaIndustry/naturalGas/ConventionalUnconventional/Pages/default.aspx#xHoZ68M4VRCi [h] http://www.ucsusa.org/clean_energy/technology_and_impacts/energy_technologies/hownatural-gas-works.html [i] http://www.cpge.utexas.edu/ur/diagenetic_alteration.html [j] http://miktechnology.wordpress.com/2010/05/22/hydrates-a-novel-concept-for-pluggingdeep-sea-severed-pipeline-proposed-scenario-for-bp-gulf-of-mexico-spill [k] http://abarrelfull.com/main/modules/wiwimod/index.php?page=Geopressurized+Zones [l] http://www.claysandminerals.com/materials/shales accessed 03.12.2011 [m] http://naturalgas.org/environment/technology.asp [n] http://ofpeaceandpolitics.wordpress.com [o] http://www.netl.doe.gov/technologies/oilgas/publications/brochures/Shale_Gas_March_2011.pdf [p] http://esa21.kennesaw.edu/activities/coal/coalactivity.pdf [q] http://esa21.kennesaw.edu/activities/naturalgas/naturalgas.pdf [r] http://esa21.kennesaw.edu/activities/oil/oilactivity.pdf

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