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An introduction to shale gas

June 2011

Shale Gas vs Conventional Gas

Natural gas resources are typically divided into two categories: conventional and unconventional. Conventional gas typically is found in reservoirs with permeabilities greater than 1 millidarcy ("mD") and can be extracted via traditional techniques. A large proportion of the gas produced globally to date is conventional, and is relatively easy and inexpensive to extract. In contrast, unconventional gas is found in reservoirs with relatively low permeabilities (less than 1 mD) and hence cannot be extracted via conventional methods. There are several types of unconventional gas resources that are produced today but the three most common types are tight gas, coal bed methane and shale gas. Given the low permeability of these reservoirs, the gas must be developed via special techniques including fracture stimulation (or "fraccing") in order to be produced commercially.

Shale Play Properties

Shale gas is natural gas that is produced from a type of sedimentary rock derived from clastic sources often including mudstones or siltstones, which is known as shale. Clastic sedimentary rocks are composed of fragments (clasts) of pre-existing rocks that have been eroded, transported, deposited and lithified (hardened) into new rocks. Shales contain organic material which was lain down along with the rock fragments. In areas where conventional resource plays are located, shales can be found in the underlying rock strata and can be the source of the hydrocarbons that have migrated upwards into the reservoir rock. Shales contain organic matter (kerogen) which is the source material for all hydrocarbon resources. Over time, as the rock matures, hydrocarbons are produced from the kerogen. These may then migrate, as either a liquid or a gas, through existing fissures and fractures in the rock until they reach the earth's surface or until they become trapped by strata of impermeable rock. Porous areas beneath these `traps' collect the hydrocarbons in a conventional reservoir, frequently of sandstone. The diagram below shows how the gas-rich shale strata are typically the source rock for conventional oil and gas reservoirs. Schematic Geology of Natural Gas Resources

Source: US Energy Information Administration Shale gas resource plays differ from conventional gas plays in that the shale acts as both the source for the gas, and also the zone (also known as the reservoir) in which the gas is trapped. The very low permeability of the rock causes the rock to trap the gas and prevent it from migrating towards the surface. The gas can be held in natural fractures or pore spaces, or can be adsorbed onto organic material. With the advancement of drilling and completion technology, this gas can be successfully exploited and extracted commercially as has been proven in various basins in North America.

Aside from permeability, the key properties of shales, when considering gas potential, are total organic content ("TOC") and thermal maturity. TOC is the total amount of organic material (kerogen) present in the rock, expressed as a percentage by weight. Generally, the higher the TOC, the better the potential for hydrocarbon generation. The thermal maturity of the rock is a measure of the degree to which organic matter contained in the rock has been heated over time, and potentially converted into liquid and/or gaseous hydrocarbons. Thermal maturity is measured using vitrinite reflectance (Ro). Because of the special techniques required for extraction, shale gas can be more expensive than conventional gas to extract. On the other hand, the in-place gas resource can be very large given the significant lateral extent and thickness of many shale formations. However, only a small portion of the world's shale gas is theoretically producible and even less likely to be producible in a commercially viable manner. Therefore a key determinant of the success of a shale play is whether, and how much, gas can be recovered to surface and at what cost.

The Rise of Shale Gas in the US

Shale gas technology has been largely pioneered in the US and the emergence of US shale gas plays has fundamentally altered the US natural gas supply picture. The first shale gas well in the US commenced production in 1821 from a well near Fredonia, New York. Low levels of shale gas production occurred between this period and the year 2000 and it has only really been since 2006 that the shale gas industry in the US has started to gain significant momentum.

Overview of Key US Shales

The figure below shows an overview of the key US shale plays. Whilst the distribution of oil and gas bearing shales across the US subsurface is much larger than shown in the map, only a relatively small number of these are currently being developed. US Shale Gas plays

The chart below shows the estimated volumes of technically recoverable resources in four of the leading US shale plays compared with some of the world's largest conventional gas fields (Source: Chesapeake--2010 Institutional Investor and Analyst Meeting, 13/10/2010). The Marcellus shale and the Haynesville shale stand out as two of the three largest known gas resources in the world. Comparison of us shales and global conventional gas resources

Source: Chesapeake--2010 Institutional Investor and Analyst Meeting, 13/10/2010 (slide 47)

Gas Shale Challenges and Solutions

As mentioned earlier the gas storage properties of shales are quite different to conventional reservoirs. In addition to having gas present in the matrix system of pores similar to that found in conventional reservoir rocks, shales also have gas bound or adsorbed to the surface of organic materials in the shale. The relative contributions and combinations of free gas from matrix porosity and from desorption of adsorbed gas is a key determinant of the production profile of the well. The amount and distribution of gas within the shale is determined by, amongst other things, the initial reservoir pressure, the petrophysical properties of the rock, and its adsorption characteristics. During production there are three main processes at play. Initial gas production is dominated by depletion of gas from the fracture network. This form of production declines rapidly due to limited storage capacity. After the initial decline rate stabilises, the depletion of gas stored in the matrix becomes the primary process involved in production. The amount of gas held in the matrix is dependent on the particular properties of the shale reservoir which can be hard to estimate. Secondary to this depletion process is desorption whereby adsorbed gas is released from the rock as pressure in the reservoir declines. The rate of gas production via the desorption process depends on there being a significant drop in reservoir pressure. Pressure changes typically advance through the rock very slowly due to low permeability. Tight well spacing can therefore be required to lower the reservoir pressure enough to cause significant amounts of adsorbed gas to be desorbed. These overlapping production processes result in the characteristic hyperbolic production profile that declines sharply (typically by 60-80 per cent.) over the first year. The diagram below shows how production rates for shale wells in four plays in the US vary over time

US Shale Gas plays


Pro du ction Rate (mmcfe/d)

10.0 8.0 6.0 4.0 2.0 0.0 0 1 2 3 4 5 6 En d o f Ye ar 7 8 9 10

Marcellus Haynesville Barnett Fayetteville

Source: Chesapeake--2010 Institutional Investor and Analyst Meeting, 13/10/2010 (slide 54) Due to these particular properties, the ultimate recovery of the gas in place surrounding a particular shale gas well can be in the order of 28-40 per cent. (whereas the recovery per conventional well may be as high as 60-80 per cent.). The development of shale gas plays, therefore, differs significantly from the development of conventional resources. With a conventional reservoir, each well is capable of draining oil or gas over a relatively large area (dependent on reservoir properties). As such, only a few wells (normally vertical) are required to produce commercial volumes from the field. With shale gas projects, a large number of relatively closely spaced wells are required to produce large enough volumes to make the plays economic. As a result, many wells must be drilled in a shale play to drain the reservoir sufficiently. In the Barnett play in the US, the drilling density can exceed one well per 60 acres.

Key Shale Gas Production Techniques

As stated earlier, shales have very low permeability (measured in nanodarcies). As a result of this, many wells are required to deplete the reservoir, and special well design and well stimulation techniques are required to deliver production rates of sufficient levels to make a development economic. Horizontal drilling and fracture stimulation have both been crucial in the development of the shale gas industry.

Horizontal Drilling

Horizontal drilling is a technique that allows the wellbore to come into contact with significantly larger areas of hydrocarbon bearing rock than in a vertical well. As a result of this increased contact, production rates and recovery factors can be increased. As the technology for horizontal drilling and fraccing has improved, the use of horizontal drilling has increased significantly. In the Barnett shale in the US, for example, the number of horizontal wells drilled in 2001-03 was 76. In 2007-08 this number had risen to 1,810. Over the same interval, the number of new vertical wells in the Barnett declined from 2,001 to just 131.

Hydraulic Fracture Stimulation

Hydraulic fracture stimulation, or "fraccing", is a process through which a large number of fractures are created mechanically in the rock, thus allowing the natural gas and/or crude oil trapped in subsurface formations to move through those fractures to the wellbore from where it can then flow to the surface. Fraccing can both increase production rates and increase the total amount of gas that can be recovered from a given volume of shale. Pump pressure causes the rock to fracture, and water carries sand ("proppant") into the hydraulic fracture to prop it open allowing the flow of gas. Whilst

water and sand are the main components of hydraulic fracture fluid, chemical additives are often added in small concentrations to improve fracturing performance.

Pad Drilling

In shale drilling it is becoming increasingly common to use a single drill pad to develop as large an area of the subsurface as possible. One surface location may be used to drill multiple wells. Pad drilling increases the operational efficiency of gas production and reduces infrastructure costs and land use. Any negative impact upon the surface environment is therefore mitigated.

Stacked Wells

The drilling of stacked horizontal wells may be possible where the shale is sufficiently thick or multiple shale rock strata are found layered on top of each other. One vertical well bore can be used to produce gas from horizontal wells at different depths. One area where this technology is being employed is in the Pearsall and Eagle Ford plays in southern Texas. Cost savings and efficiencies can be achieved as surface facilities are shared. As in pad drilling, the environmental impact on the surface is mitigated as a result of reduced land use. This technology can be particularly beneficial in the thicker shales.

Multilateral Drilling

Multilateral drilling is similar to stacked drilling in that it involves the drilling of two or more horizontal wells from the same vertical well bore. With multilateral drilling, the horizontal wells access different areas of the shale at the same depth, but in different directions. With the drilling of multilateral wells it is possible for production rates to be increased significantly for a reduced incremental cost. The diagrams below show examples of pad drilling (Source: Tyndall Centre Report--Shale Gas: A Provisional Assessment of Climate Change and Environmental Impacts, January 2011) and multilateral wells (Source: Baker Hughes INTEQ). Pad drilling Multi-lateral drilling

Benefits of Technology Improvements Decline in Drilling Costs

Due to the extensive reliance on horizontal drilling and hydraulic fracturing, the costs associated with the development of shale resources can be significantly higher than for conventional oil and gas. However, these costs have been driven down over the past decade in North America due to efficiency improvements resulting from large scale drilling programmes and the use of pad drilling and stacked or multilateral wells. Thus, Chesapeake Energy reported achieving significant improvements in drilling times and costs in the Barnett shale in 2010. The graph below shows improvements in drilling times and costs achieved by Encana in the Piceance Basin from 2006 to 2010.

Development of Piceance Shale Days to Drill

Development of Piceance Shale Drilling Cost

Source: Encana--Division Overview March 2010

Decline Mitigation and Increased Recovery

A combination of improved technology and shale-specific experience has also led to improvements in recovery factors and reductions in decline rates. Each shale play requires its own specific completion techniques, which can be determined through careful analysis of rock properties. The correct selection of well orientation, stimulation equipment, fracture size and fraccing fluids can all affect the performance of a well. The initial production ("IP") rate from a particular well is highly dependent on the quality of the frac and the well completion. In the US it has been seen that IP rates have been augmented over time as the play matures (see below in the Haynesville). IP rates can be increased by several techniques, in particular by increasing the number of frac stages and increasing the number of perforations per frac stage. The quality of the frac is also improved as fluid properties are developed. Microseismic data can also be used to improve the efficiency of the fraccing process.

Development of Haynesville IP Rate

Source: Chesapeake Energy--2010 Investor and Analyst Meeting Presentation For developed shales in North America the combined benefits of improved technology and increased experience have resulted in the upward shift of well type curves (expected well production curves) over time. Both the expected ultimate recovery per well and the peak production per well have been seen to increase as plays have matured.

Environmental Considerations Water Usage and Recycling

A large volume of water is needed for the development of shale gas plays. Water is used for drilling, where it is mixed with clays to form drilling mud. This mud is used to cool and lubricate the drill-bit, provide well-bore stability and also carry rock cuttings to the surface. Water is also used in significant volumes in hydraulic fracturing. In addition to water and sand, a small concentration of other additives is added to the fluid to improve fraccing efficiency. Chesapeake Energy cites a figure of 4.5 million gallons of fluid for the fracturing of a typical horizontal well. This significant volume of water needs a plentiful source. In the US, the water is typically trucked to the drilling location or transported via temporary pipelines. A typical fraccing fluid

Source: Chesapeake--Hydraulic Fracturing Fact Sheet A typical fraccing fluid is more than 98 per cent. water and sand. The other 2 per cent. is made up of a number of additives which may vary depending on the particular well and operator (Source: Chesapeake--Water Use Fact Sheet). Typically additives include many substances that are commonly found in small measure in various household products. The range of additives shown in the diagram above, and the purpose of each, is set out in the table below.

Product Water and Sand: >98% Water


Downhole result

Other common uses

Expand fracture and deliver sand Allows the fractures to remain open so the gas can escape

Some stays in formation while remainder returns with natural formation water as "produced water" (actual amounts returned vary from well to well). Stays in formation, embedded in fractures (used to "prop" fractures open).

Landscape, manufacturing Drinking water filtration, play sand, concrete and brick mortar

Sand Proppant

Other additives: <2% Acid Helps dissolve minerals and initiate cracks in the rock Prevents the corrosion of the pipe Reacts with minerals present in the formation to create salts, water, and carbon dioxide (neutralised). Bonds to metal surfaces (pipe) downhole. Any remaining product not bonded is broken down by microorganisms and consumed or returned in produced water. Reacts with minerals in the formation to create simple salts, carbon dioxide and water all of which are returned in produced water. Reacts with microorganisms that may be present in the treatment fluid and formation. These micro organisms break down the product with a small amount of the product returning in produced water. Product attaches to the formation downhole. The majority of product returns with produced water while remaining reacts with microorganisms that break down and consume the product. Reacts with clays in the formation through a sodium--potassium ion exchange. Reaction results in sodium chloride (table salt) which is returned in produced water. Remains in the formation where temperature and exposure to the "breaker" allows it to be broken down and consumed by naturally occurring micro organisms. A small amount returns with produced water. Generally returned with produced water, but in some formations may enter the gas stream and return in the produced natural gas. Swimming pool chemical and cleaner Pharmaceuticals, acrylic fibres and plastics Food additive; food and beverages; lemon juice Disinfectant; steriliser for medical and dental equipment

Corrosion Inhibitor

Iron Control

Prevents precipitation of metal (in pipe) Eliminates bacteria in the water that produces corrosive byproducts

Anti-Bacterial Agent

Scale Inhibitor

Prevents scale deposits downhole and in surface equipment Prevents formation clays from swelling

Household cleansers, deicer, paints, and caulk Lowsodium table salt substitute, medicines, and IV fluids Cosmetics including hair, makeup, nail and skin products

Clay Stabliser

Friction reducer

"Slicks" the water to minimise friction


Used to increase the viscosity of the fracture fluid

Glass cleaner, multisurface cleansers, antiperspirant, deodorants and haircolour Cosmetics, baked goods, ice cream, toothpaste, sauces, and salad dressings Hair colouring, as a disinfectant, and in the manufacture of common household plastics Laundry detergents, hand soaps and cosmetics Laundry detergents, soap, water softener and dish washer detergents

Gelling Agent

Thickens the water in order to suspend the sand

Combines with the "breaker" in the formation thus making it much easier for the fluid to flow to the borehole and return in produced water. Reacts with the "crosslinker" and "gel" once in the formation making it easier for the fluid to flow to the borehole. Reaction produces ammonia and sulphate salts which are returned in produced water. Combines with the "breaker" in the formation to create salts that are returned in produced water. Reacts with acidic agents in the treatment fluid to maintain a neutral (nonacidic, nonalkaline) pH. Reaction results in mineral salts, water and carbon dioxide which is returned in produced water.


Allows a delayed break down of the gel


Maintains fluid viscosity as temperature increases Maintains the effectiveness of other components, such as crosslinkers

pH Adjusting Agent

Source: Chesapeake--Water Use Fact Sheet

During a typical hydraulic fracturing process the frac fluid is transmitted down a cased well-bore to the target zones and then forced deep into the targeted shale gas formations. In order to minimise the risk of any groundwater contamination, good drilling practice normally requires that one or more strings of steel casing are inserted into the well and cemented into place so as to ensure that the entire wellbore, other than the production zone, is completely isolated from the surrounding formations including aquifers. Most oil or gas-bearing shales in the US tend to be at least 1,500m below the surface, whereas aquifers are generally no more than 500 metres below the surface. Given the thickness of rock separating target shale formations from overlying aquifers, and the extremely low permeability of shale formations themselves, and also assuming the implementation of good oilfield practices (such as casing and cementing), it is considered by the industry that the risk of contamination of overlying aquifers as a result of hydraulic fracturing operations is remote. Instances where contamination of aquifers has been alleged are generally believed to have involved poor drilling practices, in particular poor casing and cementing of a well or poor construction of surface storage facilities. Currently, most of the flowback fluid from fraccing operations is either transported from well sites for disposal or is processed for re-use in further operations. Suspended solids must be removed from the water before re-use. The recycling of this water can be costly and is a major focal point of many environmental groups and environmental regulators. New, more efficient, technologies have been developed which allow frac fluid to be recycled on-site at reduced cost. Fluids other than water may be used in fraccing processes, including CO2, nitrogen or propane, although their use is currently much less widespread than water.

The Shale Gas Industry in Poland The Emergence of Shale in Europe

Following on from the dramatic advances in shale hydrocarbons technology and shale oil and gas production in the US, a number of oil and gas companies have started to look for opportunities to apply the techniques developed in North America in new geological basins and markets outside North America. A considerable number of regions around the world have been the focus of interest for their shale potential. In a report commissioned by the US Energy Information Agency `World Gas Shale Resources: An Initial Assessment of 14 Regions Outside the United States' published by the EIA in April 2011 (the "EIA Report"), 48 major shale basins are identified in 32 countries around the world. 48 Major Shale Basins in 32 countries

Source: EIA The EIA Report identifies a number of plays across Europe where organic-rich shales are present, including: I. Lower Paleozoic shales, spreading from Eastern Denmark and Southern Sweden to Northern and Eastern Poland; II. Carboniferous shales, spreading from North-West England through Netherlands and NorthWest Germany to South-West Poland; and III. Lower Jurassic bituminous shales, spreading from the South of England to the Paris Basin in France, the Netherlands, Northern Germany and Switzerland. The EIA Report further identifies Poland and France as countries with some of the largest estimated shale gas technically recoverable resources in Europe. Both countries are also highly dependent on imported gas to meet domestic demand.

Shale in Poland

Of the various European shale plays, Poland is among the most advanced in terms of exploration for and appraisal of unconventional gas resources. The shales are deposited in three basins--the Baltic in the north, the Lublin in the south, and the Podlasie in the east (see map below). The organically rich shales in these three basins appear to have favourable characteristics for shale gas exploration. Major Shale Basins of Poland

Source: Advanced Resources International, Inc. / EIA

The EIA Report estimates that Poland has 792 TCF of risked shale gas-in place, comprising 514 TCF in the Baltic Basin, 222 TCF in the Lublin Basin and 56 TCF in the Podlasie Basin. The EIA Report estimates a risked technically recoverable shale gas resource of 187 TCF from these three basins. The 8,846 square mile shale gas prospective area in the Baltic Basin was determined by the EIA Report using the depth and thermal maturity of the Llandovery Formation. The formation shallows to the northwest, where its prospective area is limited by lack of sufficient thermal maturity. In the deep, western margin of the basin, the Llandovery Formation is highly thermally mature, values greater than 5.0 per cent. However, the basin becomes very deep in this area. In the western areas, the prospective area is limited by the 5,000 metres depth contour interval. Onshore Baltic Basin, Lower Silurian Llandovery shale depth and structure

Entry of Major Players in Recent Years

One of the first organisations to recognise the potential of shale gas in Poland was the 3 Legs Resources Group. Following the entry of 3Legs Resources Group, there was a rapid take up of acreage in 2009 and 2010 both by smaller exploration and production companies, and by some of the major international companies including ExxonMobil, ConocoPhillips, Chevron, Marathon Oil, Eni and Total. As at the date of this note, exploration drilling is being either contemplated or carried on by these organisations. Only when this work has been carried out will the true potential of Polish shales be understood. June 2011.


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