The phenomenon of shale gas is both topical and controversial. Its proponents claim that it is a clean, environmentally friendly and abundant source of cheap natural gas; its opponents believe the opposite. In several countries it is a fast-growing industry and operations have begun in the UK. With conventional reserves of natural gas being quickly depleted, gas prospecting is turning to “unconventional resources”, one example being gas found in shale. Uncommon technologies, notably hydraulic fracturing and horizontal drilling, are necessary for shale extraction to be economical. Shale gas has faced some difficulties over concerns regarding environmental pollution. In the US, Gasland, an influential film was released alleging that waste fluid from hydraulic fracturing, “flowback water”, was polluting groundwater. While it is possible for methane to enter groundwater through a faulty well completion, in the UK it is the responsibility of the Environment Agency and HSE to ensure regulation is adequate to prevent risks to the environment or human health. There have been two earthquakes in Lancashire thought to have been caused by shale gas operations. The results of an investigation into these have been accepted as revealing that they were caused by hydraulic fracturing operations and new guidelines are being proposed to reduce the risk of this happening again. With insufficient public information and sometimes animosity towards shale gas, drillers need to consider developing corporate social responsibility programs tailored to the needs of the communities local to drilling, with especial consideration towards environmental initiatives. Worldwide, shale gas has had a significant and growing impact on gas production and looks likely to rapidly transform the energy situation. In Europe, Poland and France have the largest reserves; Poland has embarked on a program to exploit its shale gas reserves. France, on the other hand, has outlawed the hydraulic fracturing technology vital to shale gas on environmental grounds. The UK's shale gas reserves are unlikely to be large enough to be a “game changer”; however, they would contribute to gas security and the UK's energy mix, as well as being perceived as a lower-carbon alternative to coal-fired electricity generation. There are already substantial reserves of gas available worldwide; however, the development of these unconventional gases, which are often in more politically stable parts of the world, may provide a greater security of supply to the Western World going forward.
As the existing conventional gas supplies have started to decline in some parts of the western world, the search has been on for alternative secure sources of supply. One of the most exciting developments in the last 20 years in the natural gas sector has been the development of unconventional gases and, in particular, the exploration and production of shale gas. The existence of shale gas has been known for decades but technological difficulties and substantial financial costs associated with its extraction have up until recently made its exploitation uneconomic. However, increased demand and lagging supply have resulted in the price of gas rising to the point where, along with the development of advances in drilling, shale gas has started to represent a viable alternative to conventional sources of supply. Shale gas is now being produced in large quantities in the USA as their industry has developed over the last decade. Exploitation of reserves is now progressing in other parts of the world, including Poland and Australia. In addition, exploration is starting in other countries including the UK but the development of shale gas production, which often includes hydraulically fracturing of the rock (otherwise known as fracking), is not without its opponents. In America the film, Gasland, raised issues relating to problems associated with fracking which has caused some people to have environmental concerns. In some countries, such as France, an embargo has been placed on fracking and even within the USA some states are not as yet permitting it. There have been reports of ground-water contamination which has resulted in illnesses, gas coming out of water taps, and earthquakes caused by fracking. However, in many parts of the world shale gas is seen as a secure source of hydrocarbon that cannot be ignored. Development is seen in many countries as a way to secure energy supplies that is independent of events in the more volatile parts of the world where most of the existing gas and oil reserves are located.
In 1821 shale gas was produced from a natural seepage in the Appalachian Mountains at Fredonia, New York, USA. It was trapped and piped in hollow logs where it was used to light homes and businesses. The profit margins were small and small local operators exploited it as a “cottage industry”.1
In the late 1960s and early 1970s it was clear that the political situation in the Middle East was changing. There had been Arab–Israeli wars in 1967 and 1973 and the situation led to dramatically increased prices for oil as well as supply shortages. The Organisation of the Petroleum Exporting Countries (OPEC)† also rose to international prominence during the 1970s, as its Member Countries took control of their domestic petroleum industries and acquired a major say in the pricing of crude oil on world markets. On two occasions, oil prices rose steeply in a volatile market, triggered by the Arab oil embargo in 1973 and the outbreak of the Iranian Revolution in 1979. OPEC broadened its mandate with the first Summit of Heads of State and Government in Algiers in 1975, which addressed the plight of the poorer nations and called for a new era of cooperation in international relations in the interests of world economic development and stability. This led to the establishment of the OPEC Fund for International Development in 1976. Member Countries embarked on ambitious socio-economic development schemes. It was against this background of volatile oil prices and trying to ensure security of supply that, in 1976, the United States Department of Energy initiated the Eastern Shales Project at a cost of up to $200 million to evaluate the geology, geochemistry and petroleum production engineering of non-conventional petroleum, including shale gas. Important reports established findings from what was then the only shale gas production in the world,2 based on the Devonian and Mississippian shales in the Appalachian basin.3 These reports led to the establishment of the Gas Research Institute and also stimulated research at Imperial College in the United Kingdom looking at evaluating potential resources. The geology of the plate tectonics of the Atlantic Ocean implied that the continuation of the Appalachian basin extended across into the UK and on into mainland Europe (see Figure 1). Imperial College focussed on the US paradigm of “cottage industry” and reviewed potential shale gas extraction from throughout the rock strata.4 The study concluded that Pre-Cambrian and Lower Palaeozoic shales were generally too metamorphosed to be potential reservoirs and most Mesozoic and younger organic-rich shales and mudstones were deemed too immature to be considered. Carboniferous shales, in general, and Namurian shales, in particular, were found to be ideally suited, both in terms of maturity and in degree of natural fracturing (see Figure 2). During the late 1970s, profit made from gas extraction was subject to both Corporation Tax and Petroleum Revenue Tax, meaning that production was nowhere near economic.
The conclusions of the Imperial College study on shale gas potential in the UK were presented to the UK Department of Energy in 1985. They were met with polite interest but the chances of shale gas being exempt from Petroleum Revenue tax was not countenanced. Subsequent attempts to inform the wider world failed and no reputable scientific journal would publish papers on the UK's shale gas resources. Finally, conclusions of the research were published in the US.4 Meanwhile in the US, shale gas development was continuing in the Appalachians, from a geographic perspective as well as from the study of rock strata, especially the distribution, deposition and age of sedimentary rocks, and various technological advances were also being looked at. The Appalachian basin, from New York State through Ohio to Kentucky and Illinois, was the main historic area for shale gas production, but there had been other basins where the gas was produced, such as the Williston Basin. This is a large intracratonic sedimentary basin in eastern Montana, western North Dakota, South Dakota and southern Saskatchewan where the Bakken Shale had produced gas since 1953. Stimulated by the Department of Energy and the Gas Research Institute, shale gas areas were found in the Cretaceous Lewis Shale of the San Juan Basin, the Mississippian Barnett Shale of the Fort Worth Basin and the Devonian Antrim Shale of the Michigan Basin.5 Geochemical studies revealed that the gas was not produced by microorganisms that generate heat within organic waste (thermogenic) but was produced by bacterial anaerobic respiration (methanogenesis). The bacteria had entered the fractured shale from ground water percolating down from the glacial drift cover.6 This second process for gas generation opened up new areas for exploration: areas where the source rock was previously deemed immature or over-mature for thermogenic gas generation.
The shale gas renaissance was also brought about by improved methods of well drilling and advances in completion technologies. The ability to drill multiple wells off a single pad was both financially and environmentally rewarding.7 The ability to drill wells horizontally as well as vertically, together with the ability to steer the drill along “sweet spots”, enabled permeable gas-changed zones to be tapped into. This was coupled with more dramatic hydraulic fracturing techniques. Seismic techniques, which could use the fracturing process as an energy source, enabled gas-charged “sweet spots” to be mapped in three dimensions.1
In the US the development of shale gas expanded dramatically from the mid 1990s, with the number of gas rigs in operation increasing from around 250 in 1993 to over 1500 by 2007.8 This has seen production of shale gas in the US increase from 1293 billion cubic feet in 2007 to 7994 billion cubic feet in 2011.9 This has resulted in the US natural gas wellhead price falling from $8.01 per thousand cubic feet in January 2006 to $2.89 per thousand cubic feet in January 2012.9 These are similar prices to those seen in the US in the early 1980s. However, the reduction in the price of natural gas seen in the US is unlikely to be repeated to the same extent in Europe. This is due to the limited export market that the US has for gas at the present time as it has no export terminals for shipping the gas globally as liquefied natural gas (LNG). The largest exporter of LNG worldwide, Qatar, has six operational export terminals, whilst Australia, which is rapidly increasing its export of LNG, has three operational export terminals with another seventeen projects either under construction or being planned. Worldwide there are thirty-two operational export terminals with another sixty-nine under construction or in planning.10
In the UK, shale gas as a potential industry did not develop at all until the British Geological Survey (BGS) noted the potential for its production in 1995.11 Shale gas was not mentioned in reviews of future UK petroleum resources published in 2003 by the Oil and Gas Directorate of the Department of Trade & Industry.12 The 6thPetroleum Geology Conference on the Global Perspectives of North West Europe was held later in the same year. The three-day programme concluded with a session on non-conventional petroleum. This included a presentation on the UK's shale gas resources and provided a platform to disseminate updated conclusions of the Imperial College research of some 15 years previously. The advances in US shale gas exploration and production technology could now be applied to the UK.13 In 2008 the British Geological Survey began to review UK shale gas resources and delivered a presentation on their results at the 7thPetroleum Conference in March 2009. Subsequently, the Department of Energy & Climate Change commissioned the BGS to prepare a report on The Unconventional Hydrocarbon Resources of Britain's Onshore Basins – Shale Gas.14
The result of this was that several companies started to look at shale gas sites within the UK at the time of the announcement of the 13th onshore round of UK licences in 2006. In 2008 Wealden Petroleum Developments Ltd was awarded a license that covered large parts of the Weald, an area in South East England situated between the parallel chalk escarpments of the North and the South Downs, for exploration. Additionally, Cuadrilla Resources Corporation was awarded a licence that includes areas of the North West of England.
As noted, horizontal drilling and hydraulic fracturing are the two technologies that together have the potential to unlock the tighter shale gas formations.
Hydraulic fracturing (also known as “fracking”) is a well-stimulation technique which consists of pumping a fluid and a propping agent (“proppant”), such as sand, down the wellbore under pressure to create fissures in the hydrocarbon-bearing rock. Propping agents are required to “prop open” the fracture once the pumps are shut down and the fracture begins to close. The ideal propping agent is strong, resistant to crushing, resistant to corrosion, has a low density and is readily available at low cost. The products that best meet these desired traits are silica sand, resin-coated sand (RCS) and ceramic proppants. The fractures start in the horizontal wellbore and can extend for several hundred metres while the sand holds the fissures apart, allowing the gas to flow into the wellbore. Recovery of the injected fluids is highly variable, depending on the geology, and ranges from 15 to 80%.15
Horizontal drilling allows the well to penetrate into the hydrocarbon rock seam which can be typically 90 m thick in the US, but can be up to 1000 m thick in some of the UK shale gas seams. Horizontal drilling maximises the rock area that, once fractured, is in contact with the wellbore and therefore maximises the volume of shale gas that is released.
Horizontal drilling is performed with similar equipment and technologies to that which has been established over decades for vertical drilling and, in fact, the initial drilling of the vertical bore is almost identical to a conventional well. However, the well development and gas extraction processes differ widely between conventional and unconventional gas production. Whilst some conventional wells have been stimulated by hydraulic fracturing in the past, horizontal drilling and hydraulic fracturing are key requirements to make the exploitation of shale gas deposits economically viable.
The requirement for horizontal drilling and hydraulic fracturing also results in differences in the distribution of wells above the shale gas formations. The process involves locating several individual wells on a single “multi-well” pad. Normally 6–10 horizontal wells radiate out from the centre well pad; these then are drilled in parallel rows, typically 5–8 m apart. Each horizontal wellbore is typically 1–1.5 km in lateral length, although they can be considerably longer.
As the array of wells drilled from each pad only enables access to a discrete area of the shale formation, several multi-well pads in a geographic area are required in order to maximise shale gas extraction. In the US they typically locate a maximum of nine pads per square mile. In the UK, Composite Energy has estimated that about three pads per square mile should be sufficient for the UK setting.16 However, the geological and above-ground constraints will also impact on the location of well pads.
The differences in the production process between conventional and unconventional gas production also results in differences in the level of effort required to extract shale gas. It also affects the amount of resources used and the corresponding volume of waste products generated.
As already stated previously, the pads used for multi-well drilling require an area of land sufficient to accommodate fluid storage and equipment associated with the hydraulic fracturing operation. This utilises larger equipment for horizontal drilling than that required for vertical drilling only. This results in between 0.4 and 1.2 ha (1–3 acres) of land being required for a multi-well pad.
Vertical drilling depth will vary dramatically, depending on the depth of the shale gas strata and their location. However, it is expected that wells will be drilled through rock layers and aquifers for a distance of up to 2 km, to within 150 m of the top of the shale gas rock to be hydraulically fractured. A more powerful horizontal drill may then be used for the horizontal portion of the wellbore. This transition is known as “kicking off” and the horizontal well is then continued for an additional 1–1.5 km.
The vertical portion of the well is typically drilled using either compressed air or freshwater mud as a drilling fluid. Once the horizontal section is ready to be drilled, then this normally requires drilling mud for powering and cooling the down-hole motor that is used for the directional drilling. The drilling mud also provides stability for the horizontal drilling and for using the navigational tools, which require mud to transmit the sensor readings that enable the bore to be accurately traced. The mud also enables the removal of the cut material from the drilling operation. The drilling mud is a heavier mud than the freshwater mud used in the vertical drilling due to the need to prevent hole collapse of the horizontal wellbore where the earth's vertical stress is much greater than in the vertical bore.
Developments are being undertaken to drill the horizontal bore pneumatically, using specialist equipment to control fluids and gases entering the wellbore. It will be interesting to see which method will come to dominate the horizontal drilling operation, although it could be the geology or water availability that determines the approach adopted.
In terms of waste material generated from the process, if the vertical well was 2 km deep with a 1.2 km lateral well the volume of waste would be in the region of 140 cubic metres, whereas a conventional well drilled to the same depth of 2 km would generate about 85 m3 of waste material. Therefore a 10-well pad would generate 1400 m3 of waste.
Well casings17 are installed to seal the well from the surrounding formation and to stabilise the completed well. A number of these may be installed to meet a variety of circumstances and are typically concentric steel pipes lining the inside of the drilled hole, with the annular spaces filled with cement. There are four casing “strings”, each installed at different stages in drilling. The first is the “conductor casing” this is installed during the first phase of drilling; it is a shallow steel conductor casing installed vertically to reinforce and stabilise the ground surface, the depth of the conductor casing is typically 40–300 ft. This is followed by the “surface casing”. After the installation of the conductor casing, drilling continues to below the bottom of the freshwater aquifers (depth requirements for groundwater protection are likely to be the subject of approval from the Environment Agency in the UK), at which point a second casing of smaller diameter (the surface casing) is installed and cemented in (see Figure 3).
Intermediate casings of still smaller diameter are sometimes installed from the bottom of the surface casing to a deeper depth. This is usually only required for specific reasons such as additional control of fluid flow and pressure effects or for protection of other resources such as minable coals or gas storage zones. It could, of course, form part of the requirements from the regulatory authorities in the UK.
Regulation in the UK is controlled by a variety of national and local government departments with a variety of different responsibilities. In the UK the environmental considerations are controlled by the following organisations: The Environmental Agency (EA) in England, the Scottish Environmental Protection Agency (SEPA) in Scotland and the Environmental Agencies of Wales and Northern Ireland. The Department of Energy and Climate Change administers the licensing system while the Planning Authorities (generally the local authority) deal with the planning applications required for each site.
After the surface casing cement is set (and intermediate casings, if required) the well is drilled to the target shale gas formation and a “production casing” is installed, either at the top of the target formation or into it, depending on the type of well being installed (either “open hole” or “through-perforated casing”, respectively). Well completions incorporate the steps taken to transform a drilled well into a producing one. These steps include casing, cementing, perforating and installing a production tree.
Open hole completions are the most basic type and are used in formations that are unlikely to cave in. An open hole completion consists of simply running the casing directly down into the formation, leaving the end of the piping open without any other protective filters. Very often, this type of completion is used on formations that have been fractured.
Conventional through-perforated completions consist of production casing being run through the formation. The sides of this casing are perforated, with small holes along the sides facing the formation, which allows for the flow of hydrocarbons into the well hole but still provides a suitable amount of support and protection for the well hole. The process of perforating the casing involves the use of specialised equipment designed to make small holes through the casing, cementing, and any other barrier between the formation and the open well. In the past, “bullet perforators” were used, which were essentially small guns lowered into the well. The guns, when fired from the surface, sent off small bullets that penetrated the casing and cement. Today, “jet perforating” is preferred. This consists of small, electrically ignited charges that are lowered into the well. When ignited, these charges blast small holes through to the formation, in the same manner as bullet perforating.
In addition to the depth of the surface casing, the regulatory authorities in the UK are likely to put requirements on the cementing-in of the surface casing. A method known as “circulation” may be used to fill the entire space between the casing and the wellbore (the annulus or outer space between the well casing and the rock through which it has been drilled) from the bottom of the surface casing to the ground surface. Here cement is pumped down the inside of the casing forcing it up from the bottom of the casing into the space between the outside of the casing and the wellbore. Once a sufficient volume of cement to fill the annulus has been pumped into the casing, it is usually followed by pumping a volume of water into the casing to push the cement back up the annular space until the cement begins to appear at the surface. Once the cement appears at the surface the pumping of water is stopped, this ensures that the top section of the annular space is fully filled with cement and therefore there is no leakage path between the outside of the well casing and the rock through which it has been drilled. This method is regarded as the highest standard of cementation compared to other methods such as cementing of the annular space across only the deepest groundwater zone but not all groundwater zones.
Once the surface casing is in place, the regulatory authorities may require operators to install blowout-prevention equipment at the surface, to prevent any pressurised fluids encountered during drilling from moving through the space between the drill pipe and the surface casing.
The operators could also be required to completely fill the annulus with cement from the bottom to the top of the production casing. However, there could be reasons why full cementation is not always required, including the fact that in very deep wells the “circulation” technique of filling the annular space with cement (see previously) is more difficult to accomplish as cementing must be handled in multiple stages, which can result in a poor cement job or damage to the casing.
In some instances, well tubings are inserted inside the above casings. They are typically of steel pipe, but they are not usually cemented into the well.
Prior to fracturing, the last step is to install the wellhead that is designed and pressure-rated for the specific hydraulic fracturing operation. In addition to proving the equipment for pumping and controlling fluid pressure, the wellhead incorporates flowback equipment to deal with the flowback of fracturing fluid from the well and includes pipes and manifolds connected to a gas–water separator and tanks. Figure 4 shows a typical well site during a single hydraulic fracturing operation.
The fracturing procedure is carried out one well at a time, with each well having multiple stages. A multi-stage procedure begins with isolating the well to be fractured and fracturing portions of the horizontal bore, starting at the far end of the wellbore by pumping fracturing fluid in and maintaining high pressures. The process is then repeated for the next section back and typically the process to hydraulically fracture a 1.2 km horizontal bore consists of 8–13 fracture stages. The pressures used in the fracturing process range from 5000–10000 psi. To minimise the risk of any issues when using the hydraulic fracturing fluid, the operator can pump water and mud into the bore to test the production casing to at least the maximum anticipated treatment pressure. Test pressures above the maximum treatment pressures can be used but they should never exceed the casing's internal yield pressure.
The whole of the above process from construction of the access road to the well clean-up and testing can take between 500 and 1500 days, based on the experience in New York State as shown in Table 1.15
|Operation||Materials and equipment||Activities||Duration|
|Access road and well-pad construction||Backhoes, bulldozers and other types of earth-moving equipment.||Clearing, grading, pit construction, placement of road materials such as geotextile and gravel.||Up to 4 weeks per well pad|
|Vertical drilling with smaller rig||Drilling rig, fuel tank, pipe racks, well control equipment, personnel vehicles, associated outbuildings, delivery trucks.||Drilling, running and cementing surface casing, truck trips for delivery of equipment and cement. Delivery of equipment for horizontal drilling may commence during late stages of vertical drilling.||Up to 2 weeks per well; one-to-two wells at a time|
|Preparation for horizontal drilling with larger rig||Transport, assembly and setup, or repositioning on site of large rig and ancillary equipment.||5–30 days per well|
|Horizontal drilling||Drilling rig, mud system (pumps, tanks, solids control, gas separator), fuel tank, well control equipment, personnel vehicles, associated outbuildings, delivery trucks.||Drilling, running and cementing production casing, truck trips for delivery of equipment and cement. Deliveries associated with hydraulic fracturing may commence during late stages of horizontal drilling.||Up to 2 weeks per well; one-to-two wells at a time|
|Preparation for hydraulic fracturing||Rig down and removal or repositioning of drilling equipment. Truck trips for delivery of temporary tanks, water, sand, additives and other fracturing equipment. Deliveries may commence during late stages of horizontal drilling.||30–60 days per well, or per well pad if all wells treated during one mobilisation|
|Hydraulic fracturing procedure||Temporary water tanks, generators, pumps, sand trucks, additive delivery trucks and containers, blending unit, personnel vehicles, associated outbuildings, including computerised monitoring equipment.||Fluid pumping, and use of wireline equipment between pumping stages to raise and lower tools used for downhole well preparation and measurements.a Computerised monitoring. Continued water and additive delivery.||2–5 days per well, including approximately 40–100 hours of actual pumping|
|Fluid return (flowback) and treatment||Gas/water separator, flare stack, temporary water tanks, mobile water treatment units, trucks for fluid removal if necessary, personnel vehicles.||Rig down and removal or repositioning of fracturing equipment; controlled fluid flow into treating equipment, tanks, lined pits, impoundments or pipelines; truck trips to remove fluid if not stored on site or removed by pipeline.||2–8 weeks per well, may occur concurrently for several wells|
|Waste disposal||Earth-moving equipment, pump trucks, waste transport trucks.||Pumping and excavation to empty/reclaim reserve pit(s). Truck trips to transfer waste to disposal facility.||Up to 6 weeks per well pad|
|Well clean-up and testing||Well head, flare stack, waste water tanks. Earthmoving equipment.||Well flaring and monitoring. Truck trips to empty waste water tanks. Gathering line construction may commence if not done in advance.||0.5–30 days per well|
|Overall duration of activities for all operations (prior to production) for a six-well multi-well pad||500–1500 days|
|a Wireline equipment refers to cabling technology used by operators to lower equipment or measurement devices into the well for the purposes of well intervention, reservoir evaluation and pipe recovery.|
In the USA the onshore shale gas industry has developed with very little in the way of public dissent. The reasons for this include the fact that the land owner often owns the mineral rights as well. This has resulted in many of the landowners actively encouraging exploration and production as they can ensure contractual arrangements for a percentage of the value of the gas produced. This has resulted in the landowners acquiring considerable personal wealth from the development of shale gas wells. The population density in the areas of production is often very low, so few people are affected by the issues associated with the development of the exploration and production wells.
In the UK the situation is entirely different. The mineral rights in most of the UK are owned by the state and, as such, while landowners can get money for the disruption and loss of crops, the value the landowners receive is small compared with the US. A large proportion of areas where shale gas is likely to occur are close to centres of population and therefore the potential impact on the community is greater. The initial development of the sites often involves considerable heavy vehicle movements which impacts on the local users of roads that are rural in nature and which were not designed for the number and size of the vehicles involved. The resulting noise and dust is likely to affect local residents as the exploratory well is constructed.
There are a number of environmental concerns, both real and imaginary, relating to the exploitation of shale gas in the UK, which, due to the fact that we live on a relatively small island which is heavily populated, means that the development of shale gas is invariably going to impact one community or another.
This could be in the exploration and production phase of the work or in the need to lay gas pipelines to access the existing gas distribution network. It is these issues and how the shale gas industry and the Government address them that will play a key role in allaying public concerns and convincing the public that the resources can be developed in a safe and efficient manner.
Vertical drilling is a well-established practice that has been carried out over many years and millions of wells have been drilled through aquifers with no significant issues. Drinking water aquifers are normally at depths of 300 m or less while the natural-gas-producing shale formations are typically at 3000–4000 m. Wells have metal casings between the rock and the bore, which extend well below the levels of the aquifers, and the gaps between the rock and the casings are filled with cement. The design of the casings is required to take account of the geology of the site and any fluids within them and, if necessary, there can be multiple casings extending below the drinking water aquifers to reduce the possibility of contamination. In the extremely rare cases where groundwater has been contaminated it was found to be as a result of faulty well casing installations.
There are a number of precautions that can be taken to minimise the risk to groundwater, in addition to the design and construction of the well. These include monitoring the water quality before and during the operation, having a quality assurance programme to ensure that the equipment and materials are to the correct specification and maintaining close supervision while the work is carried out. A minimum well depth can also be set to ensure adequate separation of the aquifer and the shale to be hydraulically fractured.
Concerns have been raised at the large quantities of water that are used in the process of hydraulic fracturing, particularly in areas such as the South East of England where the existing water infrastructure is under stress. The volumes required for hydraulically fracturing a single well are in the region of 10–20 million litres of water, depending on well depth, length and geology. For a typical drill pad consisting of 10 wells, this will require 100–200 million litres of water per pad. In reality, compared to the daily usage of water in the UK of 15 000 million litres per day,18 this represents a relatively small volume. Sourcing and use of water is heavily regulated and therefore the amount that can be abstracted at any time will be closely monitored and controlled to ensure that it does not have an adverse effect on other users. It should be noted that in some of the areas where shale gas deposits are located, such as the North West of England, there is abundant water and therefore the quantities of water used will have little impact on the overall water supply situation.
The cost of water, as well as its availability, will ensure that the shale gas industry is constantly attempting to reduce the volumes used by improving the hydraulic fracturing process, as well as re-using the water wherever possible to mitigate overall water requirements.
While the majority of the fluids used for hydraulic fracturing consist of more than 99.5% water and sand, companies do use a small quantity of additional chemicals to assist in the process. Although the percentage of chemical additives is small, this still equates to some 1000–3000 tonnes of chemicals for hydraulically fracturing a typical eight-well pad. The water and additives are blended on site and, when mixed with the proppant, usually sand, are pumped into the wellbore. Chemicals perform many functions in a hydraulic fracturing job. Although there are dozens to hundreds of chemicals which could be used as additives, there are a limited number which are routinely used in hydraulic fracturing. Table 2 shows a list of the chemicals used most often in America.19
|Chemical name||CAS||Chemical purpose||Product function|
|Hydrochloric Acid||007647-01-0||Helps dissolve minerals and initiate cracks in the rock||Acid|
|Glutaraldehyde||000111-30-8||Eliminates bacteria in the water that produces corrosive by-products||Biocide|
|Quaternary Ammonium Chloride||012125-02-9||Eliminates bacteria in the water that produces corrosive by-products||Biocide|
|Quaternary Ammonium Chloride||061789-71-1||Eliminates bacteria in the water that produces corrosive by-products||Biocide|
|Tetrakis Hydroxymethyl-Phosphonium Sulfate||055566-30-8||Eliminates bacteria in the water that produces corrosive by-products||Biocide|
|Ammonium Persulfate||007727-54-0||Allows a delayed break down of the gel||Breaker|
|Sodium Chloride||007647-14-5||Product Stabiliser||Breaker|
|Magnesium Peroxide||014452-57-4||Allows a delayed break down the gel||Breaker|
|Magnesium Oxide||001309-48-4||Allows a delayed break down the gel||Breaker|
|Calcium Chloride||010043-52-4||Product Stabiliser||Breaker|
|Choline Chloride||000067-48-1||Prevents clays from swelling or shifting||Clay Stabiliser|
|Tetramethyl ammonium chloride||000075-57-0||Prevents clays from swelling or shifting||Clay Stabiliser|
|Sodium Chloride||007647-14-5||Prevents clays from swelling or shifting||Clay Stabiliser|
|Isopropanol||000067-63-0||Product stabiliser and/or winterising agent||Corrosion Inhibitor|
|Methanol||000067-56-1||Product stabiliser and/or winterising agent||Corrosion Inhibitor|
|Formic Acid||000064-18-6||Prevents the corrosion of the pipe||Corrosion Inhibitor|
|Acetaldehyde||000075-07-0||Prevents the corrosion of the pipe||Corrosion Inhibitor|
|Petroleum Distillate||064741-85-1||Carrier fluid for borate or zirconate crosslinker||Crosslinker|
|Hydrotreated Light Petroleum Distillate||064742-47-8||Carrier fluid for borate or zirconate crosslinker||Crosslinker|
|Potassium Metaborate||013709-94-9||Maintains fluid viscosity as temperature increases||Crosslinker|
|Triethanolamine Zirconate||101033-44-7||Maintains fluid viscosity as temperature increases||Crosslinker|
|Sodium Tetraborate||001303-96-4||Maintains fluid viscosity as temperature increases||Crosslinker|
|Boric Acid||001333-73-9||Maintains fluid viscosity as temperature increases||Crosslinker|
|Zirconium Complex||113184-20-6||Maintains fluid viscosity as temperature increases||Crosslinker|
|Borate Salts||N/A||Maintains fluid viscosity as temperature increases||Crosslinker|
|Ethylene Glycol||000107-21-1||Product stabiliser and/or winterising agent||Crosslinker|
|Methanol||000067-56-1||Product stabiliser and/or winterising agent||Crosslinker|
|Polyacrylamide||009003-05-8||“Slicks” the water to minimise friction||Friction Reducer|
|Petroleum Distillate||064741-85-1||Carrier fluid for polyacrylamide friction reducer||Friction Reducer|
|Hydrotreated Light Petroleum Distillate||064742-47-8||Carrier fluid for polyacrylamide friction reducer||Friction Reducer|
|Methanol||000067-56-1||Product stabiliser and/or winterising agent||Friction Reducer|
|Ethylene Glycol||000107-21-1||Product stabiliser and/or winterising agent||Friction Reducer|
|Guar Gum||009000-30-0||Thickens the water in order to suspend the sand||Gelling Agent|
|Petroleum Distillate||064741-85-1||Carrier fluid for guar gum in liquid gels||Gelling Agent|
|Hydrotreated Light Petroleum Distillate||064742-47-8||Carrier fluid for guar gum in liquid gels||Gelling Agent|
|Methanol||000067-56-1||Product stabiliser and/or winterising agent||Gelling Agent|
|Polysaccharide Blend||068130-15-4||Thickens the water in order to suspend the sand||Gelling Agent|
|Ethylene Glycol||000107-21-1||Product stabiliser and/or winterising agent||Gelling Agent|
|Citric Acid||000077-92-9||Prevents precipitation of metal oxides||Iron Control|
|Acetic Acid||000064-19-7||Prevents precipitation of metal oxides||Iron Control|
|Thioglycolic Acid||000068-11-1||Prevents precipitation of metal oxides||Iron Control|
|Sodium Erythorbate||006381-77-7||Prevents precipitation of metal oxides||Iron Control|
|Lauryl Sulfate||000151-21-3||Used to prevent the formation of emulsions in the fracture fluid||Non-Emulsifier|
|Isopropanol||000067-63-0||Product stabiliser and/or winterising agent||Non-Emulsifier|
|Ethylene Glycol||000107-21-1||Product stabiliser and/or winterising agent||Non-Emulsifier|
|Sodium Hydroxide||001310-73-2||Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers||pH Adjusting Agent|
|Potassium Hydroxide||001310-58-3||Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers||pH Adjusting Agent|
|Acetic Acid||000064-19-7||Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers||pH Adjusting Agent|
|Sodium Carbonate||000497-19-8||Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers||pH Adjusting Agent|
|Potassium Carbonate||000584-08-7||Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers||pH Adjusting Agent|
|Copolymer of Acrylamide and Sodium Acrylate||025987-30-8||Prevents scale deposits in the pipe||Scale Inhibitor|
|Sodium Polycarboxylate||N/A||Prevents scale deposits in the pipe||Scale Inhibitor|
|Phosphonic Acid Salt||N/A||Prevents scale deposits in the pipe||Scale Inhibitor|
|Lauryl Sulfate||000151-21-3||Used to increase the viscosity of the fracture fluid||Surfactant|
|Ethanol||000064-17-5||Product stabiliser and/or winterising agent||Surfactant|
|Naphthalene||000091-20-3||Carrier fluid for the active surfactant ingredients||Surfactant|
|Methanol||000067-56-1||Product stabiliser and / or winterising agent.||Surfactant|
|Isopropyl Alcohol||000067-63-0||Product stabiliser and/or winterising agent||Surfactant|
One of the problems associated with identifying chemicals is that some chemicals have multiple names. For example, ethylene glycol (antifreeze) is also known by the names ethylene alcohol, glycol, glycol alcohol, Lutrol 9, Macrogol 400 BPC, monoethylene glycol, Ramp, Tescol, 1,2-dihydroxyethane, 2-dydroxyethanol, HOCH2CH2OH, dihydroxyethane, ethanediol, ethylene gycol, Glygen, Athylenglykol, ethane-1,2-diol, Fridex, MEG, 1,2-ethandiol, Ucar 17, Dowtherm SR 1, Norkool, Zerex, aliphatic diol, Ilexan E, ethane-1,2-diol and 1,2-ethanediol.
These additives are there for a number of reasons, such as helping dissolve minerals and initiate fissures; preventing scale deposits in the pipes; eliminating bacteria in the water; minimising friction between the fluid and the pipe; preventing precipitation of metal oxides; and thickening the water to suspend the sand which is used to hold the fissures generated apart. While many of the chemicals used are found in common household and commercial products, such as table salt, food additives and cosmetics, some, used in small quantities, are toxic. The number of additives used varies between 3 and 12 as the composition of the fracturing fluid is individually designed for the shale formation being fractured. In the USA the composition of the hydraulic fracturing fluid has not always been disclosed, with some of the companies maintaining that this is commercially sensitive information. This has led to suspicion by members of the public, particularly where health issues have occurred close to shale gas extraction sites. However, in the UK the composition of the fracturing fluid together with all of the additives will be fully disclosed. As a result of this and the likely public concern relating to some of the additives, companies working in the UK are likely to invest in “green” or non-toxic alternatives wherever possible.
The fracturing fluid that Cuadrilla has used at the Preese Hall exploration well site, and plans to use at future exploration well sites, is composed almost entirely of fresh water and sand. Cuadrilla also has approval to use the following additives: Polyacrylamide (friction reducer) Sodium salt (for tracing fracturing fluid) Hydrochloric acid (diluted with water) Glutaraldehyde biocide (used to cleanse water and remove bacteria)
So far, as additives to fracturing fluid, Cuadrilla has only used polyacrylamide friction reducer along with a miniscule amount of salt, which acts as a tracer. Cuadrilla have not needed to use biocide as the water supplied by United Utilities to their Lancashire exploration well sites has already been treated to remove bacteria, nor have they used diluted hydrochloric acid in fracturing fluid. Additives proposed, in the quantities proposed, have resulted in the fracturing fluid being classified as non-hazardous by the Environment Agency.
The issue of hydraulic fracturing causing earthquakes came to prominence in the UK in 2011 when two tremors, one of magnitude 2.3, hit the Fylde coast in Lancashire on the 1st April followed by a second of magnitude 1.4 on the 27th May.
Following investigation by the British Geographical Survey, the epicentre for each earthquake was identified as about 500 metres away from the Preese Hall 1 well at Weeton, Blackpool following hydraulic fracturing.
The geo-mechanical study of the Bowland Shale Seismicity report carried out by independent experts said that the combination of geological factors that caused the quakes was rare and would be unlikely to occur together again at future well sites.21
There was no damage as a result of the two earthquakes and the report stated “If these factors were to combine again in the future, local geology limits seismic activity events to around a magnitude 3 on the Richter scale as a worst-case scenario”. To put this into context, an earthquake of magnitude 2.5 or less is usually not felt but can be recorded by a seismograph, while earthquakes of magnitude 2.5 to 5.4 are often felt but only cause minor damage. Dr Cliff Frohlich of the University of Texas at Austin carried out a study of the correlation between injection wells and small earthquakes and he commented that there is a question of what kind of damage that a magnitude 3 earthquake could do to drilling infrastructure. “It's plausible that the tremors could affect well integrity,” Frohlich says. “In my business, you never say never. That said, most of the time these earthquakes are not right near the well. But it's possible an earthquake could hurt a well,” though he knows of no instances where that has occurred.22
In order to minimise the risk of future seismic events the companies now review local geology for potential fault lines prior to drilling. In addition, they monitor the process with very sensitive instruments so that the operation can be halted if there are indications that an earthquake is likely to be triggered.
Once the hydraulic fracturing is completed, fluid returns to the surface in a process known as “flowback”. The US Environmental Protection Agency (EPA) estimates that fluids recovered range from 15–80% of the volume injected, depending on the site conditions. Therefore, each well will generate 1.5–16 million litres of flowback fluids which contain water, sand, methane, fracturing chemicals and contaminants released from the rock being fractured. These contaminants could include heavy metals, organic compounds and naturally occurring radioactive materials. Approximately 60% of the flowback fluids occur within the first four days, with the remaining 40% occurring in the next ten days.
The fluids that are not recovered remain underground and concerns have been expressed that these could become a source of contamination to underground aquifers in the future. Concerns have also been expressed as to the environmental risk as a result of either waste fluids disposal or a leak from the waste fluids storage facilities. The waste fluid from hydraulic fracturing can be managed in a variety of ways, including re-use for further hydraulic fracturing, but this is more practical in multi-stage hydraulic fracturing. However, the re-use may concentrate the contaminants in the fluid, making it harder to dispose of or to remove in water treatment plants. Waste fluid can be disposed of through injection into deep underground wells, it can be treated at local water treatment facilities to make it acceptable for returning to the environment provided it meets the water treatment standards, or it can be stored in tanks or deep lined pits. The size of these pits could be substantial: to accommodate up to 160 million litres of fluid from a multi-well pad would need a pit of 160 000 cubic metres per pad.
Underground injection is the primary disposal method for most shale gas projects worldwide, but whether this will be acceptable to the United Kingdom's relevant Environmental Agencies has yet to be determined. Where injection is not an option, new wastewater treatment facilities are being built in some parts of the world. The funding for building these plants varies, with some built using local taxpayers’ money, with the gas companies paying for the volume of wastewater treated; in other cases the gas companies are paying for the construction of the plants while some are built under joint ventures with both the taxpayers and the gas companies funding the projects. The percentage of wastewater that is being recycled is increasing as companies become more adept at handling this waste and on-site treatment technologies become more readily available.
When evaluating the overall merit of any energy source many people look at the greenhouse gas emissions relative to the energy produced, e.g. the amount of greenhouse gases produced by burning coal to produce electricity. In the case of shale gas extraction, concerns have been expressed that there are significant fugitive emissions of methane associated with the process of shale gas extraction itself.
A study by Howarth et al. published in 2010 stated “Compared to coal, the (greenhouse gas) footprint of shale gas is at least 20% greater”.23 Fugitive emissions are losses of methane that occur between the well caps and the end user. These can be as a result of leakage around the site, leaks in distribution pipelines between the well and the end user, leakage from venting, etc. Most of these sources would be the same, whether it is a conventional gas well or a hydraulically fractured gas well. However, the fugitive emissions from the hydraulic fracturing process are of greater concern, as they have not been fully examined in detail and could potentially be very high.
After hydraulic fracturing but before the well is capped and the gas piped away for use, the well will be cleaned by flushing fluid or gas into the bore to remove debris and also flushing away produced methane that is not profitable to store or transport. In a study based on US Environmental Protection Agency data, academics from Cornell University have calculated that the venting of such emissions could mean that shale gas may be actually worse for global warming than coal (see Figure 5).22
Although coal releases more carbon dioxide per unit energy than methane, methane is a far more potent greenhouse gas – 72 times more powerful per unit mass than carbon dioxide over a 25-year period, falling to 25 times over a 100-year period. In the United Kingdom the Environment Agency believes that good practice can mitigate such fugitive emissions and is considering options to monitor air near the site to keep track of any leaks.
Venting in itself is a dangerous procedure, even if it were permitted in the UK by the Health and Safety Executive. Cuadrilla, which is one of the leading exploration companies operating at present in the UK, plans to flare the methane that is produced during testing prior to the production phase.24
In the US there are also concerns about methane emissions and the US EPA runs a voluntary program, EPA Natural Gas STAR, for companies adopting strategies to reduce methane emissions. These procedures are known by a variety of terms, including “the green flowback process” and “green completions.”25,26 To reduce the emissions, the gases and liquids brought to the surface during the completion processes are collected, filtered and then placed into the production pipelines and tanks instead of being dumped, vented or flared. The gas clean-up during a “green” completion is done with special temporary equipment at the well site and after a period of time (days) the gas and liquids being produced at the well are directed to permanent separators and tanks. The gas is then transported through piping and meters that are installed at the well site. Green completions methods do not involve complex technology and can be very cost effective. If this process for minimising fugitive emissions can be carried out cost-effectively in the US (where the payback period if these “Reduced Emissions Completions” are adopted is just a few months)25 then the process would make even more financial sense in the UK where gas prices are considerably higher.
Another factor in favour of capturing methane instead of flaring is that flaring produces carbon dioxide (a greenhouse gas) as well as carbon monoxide, aromatic hydrocarbons and particulate matter emissions.
The establishment of fugitive and vented emissions of methane from hydraulic fracturing, flowback and its impact on greenhouse gases is still being debated. In addition to the study by Howarth et al.,22 work has also been carried out by Jiang et al.27 and Skone,28 with each including an estimate of the methane emissions in their work.
In the case of Howarth et al., they used five industry presentations, empirical data and lifetime emissions per well and provided figures of between 140 and 6800 thousand cubic metres of methane per well completion. They used a statistical uncertainty analysis to investigate different ratios of vented and flared gas.
Jiang used an uncertainty model rather than empirical data and estimated figures per flowback event of between 30 and 1470 thousand cubic metres of methane.
Skone again used figures per flowback event, with re-fracturing being assumed to be equivalent to a completion; their data source was not clearly identified but they cited fugitive emissions between 132 and 330 thousand cubic metres of methane.
The US EPA released new estimates of fugitive emissions and revised methodologies in 2011. They derived emission factors from four studies presented at Natural Gas STAR technology-transfer workshops.29 Each study had a range of underlying individual measurements from three to over a thousand. The EPA background technical documents combine these studies to identify a figure of 260 thousand cubic metres of fugitive emissions per well completion.
The greenhouse gas impact associated with the fugitive methane gas emissions from the wells can be assumed to be similar to conventional vertical wells during the initial drilling stage, as are the levels of carbon dioxide associated with the machinery and equipment used in the drilling operation. The emissions associated with the horizontal drilling are, without more specific data being available, assumed to be the same as those emitted during vertical drilling. The California Environmental Protection Agency Air Resources Board assumes diesel fuel consumption in vertical drilling of 18.7 litres per metre drilled.30 This figure would equate to an emission factor of 49 kgCO2 m−1 of well drilling. The additional fuel required for the horizontal drilling is site-specific. However, if we assume it is similar to that used for the vertical drilling, assuming an additional horizontal drilling of a 1000 m bore could lead to an additional 49 tonnes of carbon dioxide compared to a conventional well with no horizontal drilling.
The emissions from the hydraulic fracturing process, which uses more fuel than a conventional well, relate to emissions from the fuel used by the high-pressure pumps required. New York State reports that emissions from these pumps, based on an average fuel use, for hydraulic fracturing of eight horizontally drilled wells in the Marcellus Shale used a total of 110 000 litres of diesel fuel, producing 295 tonnes of carbon dioxide per well.31
As with all industrial sites, during the construction and hydraulic fracturing phases there will be heavy road traffic moving in and out of the site. New York State (2009)15 provides estimates of truck visits to a typical site. These are summarised in Table 3, giving trips per well and per well pad (based on six wells per pad). This suggests a total number of truck visits of between 4300 and 6600 of which about 90% are associated with the hydraulic fracturing operation.
|Purpose||Per well||Per pad|
|Drill pad and road construction equipment||10||45|
|Drilling fluid and materials||25||50||150||300|
|Drilling equipment (casing, drill pipe, etc.)||25||50||150||300|
|Completion fluid and materials||10||20||60||120|
|Completion equipment (pipe, wellhead)||5||5||30||30|
|Hydraulic fracture equipment (pump trucks, tanks)||150||200|
|Hydraulic fracture water||400||600||2400||3600|
|Hydraulic fracture sand||20||25||120||150|
|Flow back water removal||200||300||1200||1800|
|… of which, associated with fracturing process:||3870||5750|
These truck visits will also have an adverse impact on greenhouse gas emissions.
During the production phase the amount of traffic will be minimal, but once the site is completed there will again be considerable heavy traffic movements as equipment is removed and the site returned to its original use.
The fossil fuel emissions of shale gas versus conventional gas per well are given in Table 4 which, in addition to the emissions associated with the horizontal drilling and the hydraulic fracturing, also takes into account the transport of water to and from the site and the wastewater treatment. Water UK estimated the emissions to the atmosphere at the wastewater treatment plant to be 0.406 tonnes of carbon dioxide per thousand cubic metres of water treated.32
|Horizontal drillinga||15–75||Horizontal drilling of 300–1500 m; 18.6 litres diesel used per metre drilled.|
|Hydraulic fracturingb||295||Based on average fuel usage for hydraulic fracturing on eight horizontally drilled wells in the Marcellus Shale. The total fuel use given is 109 777 litres of diesel fuel.|
|Hydraulic fracturing chemical productionc||–||Unknown.|
|Transportation of waterd||26.2–40.8||Based on HGV emission factor of 983.11 gCO2 km−1 and 60 km round trip.|
|Wastewater transportationd||11.8–17.9||Based on HGV emission factor of 983.11 gCO2 km−1 and 60 km round trip.|
|Wastewater treatmente||0.33–9.4||Based on 15–80% recovery of 9–29 million litres of water that is required per fracturing process and emission factor 0.406 tCO2 ML−1 treated.|
|Total per well||348–438||Based on single fracturing process.|
|a Fuel consumption from: ALL Consulting (2008). Emission factor from DUKES (2010).36 b Cited from ALL Consulting, Horizontally Drilled/High-volume Hydraulically Fractured Wells Air Emissions Data, August 2009, Table 11, p. 10 by New York State (2009).30 Emission factor from DUKES (2010).36 c A further potential source of additional emissions may be from the production of chemical used in the fracturing process. However, the level of these emissions is difficult to ascertain as: conventional wells may also include various chemicals in drilling mud, so claiming shale creates additional emissions via this route is problematic; and life cycle analysis data for these chemicals is highly specialised and is not typically publically available. d Emission factor from NAEI (2010).46 Truck numbers from Table 3. e Emission factor from Water UK – Towards sustainability (2006).31|
In the UK many of the shale gas sites will be in rural locations served by minor roads which are often narrow and of relatively light road construction to reflect the low numbers of traffic movements and minimal use by heavy vehicles. The roads are likely to pass through small villages and towns which are not accustomed to industrial developments. The high number of large lorries visiting the shale gas sites during the construction phase will subsequently result in deterioration of the road structure as well as generating dust and noise associated with the traffic movements. This is likely to be an area of serious concern to the local residents along the route the traffic will take and will result in local objections at the planning approval stage. Once the sites obtain the necessary approval, the operators of the sites could encounter traffic movement issues as local residents and the farming community compete for road space with the construction traffic which could lead to conflict between the parties. This is an issue that the shale gas companies need to address at the early planning stage to minimise disruption and to work with the local community to prevent adverse public relation issues which could impact on future projects.
The completion of drilling and hydraulic fracturing marks the start of the production phase of the wells. A production well head is put in place to collect and transfer the gas for subsequent processing, either for utilising on site for electricity production; for liquefaction and transport off site; or for piping into the gas distribution network. Production from one well can commence while other wells are being drilled and fractured.
In terms of production volumes, indicative figures for long-term production for a single Marcellus well in New York State are as follows:15 Year 1: Initial rate of 79 000 m3 per day, declining to 25 500 m3 per day Years 2 to 4: 25 500 m3 per day, declining to 15 600 m3 per day Years 5 to 10: 15 600 m3 per day, declining to 6400 m3 per day Years 11 onwards: 6400 m3 per day, declining at a rate of 3% per annum
As can be seen, after five years the volume of gas produced drops dramatically and it is at that point that the operator may decide to re-fracture the well to extend its life. Re-fracturing can take place more than once. It is anticipated that wells in the UK will follow a similar pattern of production drop-off over time.
When the productive life of a well is over, or if wells prove uneconomic to exploit, the correct procedures need to be put in place to ensure that the wells are correctly plugged and abandoned. Proper plugging is critical to protect the groundwater aquifers, surface water and soil. Well plugging involves removal of the well head and the removal of the downhole equipment. Uncemented casings in critical areas must either be pulled up or perforated. Cement must then be placed in the wellbore to seal the bore or squeezed through the perforations of the casings if they remain in place to seal between the casings, the rock formations and to fill the bore. This procedure occurs at intervals dictated by the relevant regulatory authority to ensure a seal between hydrocarbon- and water-bearing zones. As an example of how an individual American state's regulations have evolved in specific detail, California's plugging regulations require cement plugs to be placed in the following locations: a 200-foot plug straddling the surface casing shoe; a plug across oil- and gas-bearing strata that extends 100 feet above the strata; a plug extending from 50 feet below to 50 feet above the base of the water-bearing strata; and a 50-foot plug at the surface of the wellbore.33 In the UK, the Environmental Agency in England, the Scottish Environmental Protection Agency or the Environmental Agencies of Wales and Northern Ireland will require the operators to put in place procedures to ensure that there is no future release or escape of shale gas or waste water either into the environment or into groundwater-bearing strata.
In the UK, the government Department of Climate Change (DECC) defines the estimates of gas in the following terms:
Proven: reserves which, on the evidence available, are virtually certain to be technically and commercially producible, i.e. have a better than 90% chance of being produced.
Probable: reserves which are not yet proven, but which are estimated to have a better than 50% chance of being technically and commercially producible.
Possible: reserves which at present cannot be regarded as probable, but which are estimated to have a significant but less than 50% chance of being technically and commercially producible.
Terminology referring to smaller physical scales is also used. Gas Initially In Place (GIIP), or Gas In Place (GIP) for the remainder if production has commenced, refers to the total gas resource that is present in a reservoir or gas field and is a resource rather than a reserve measure. Estimated Ultimately Recoverable (EUR) refers to a given well or field over its lifetime and accounts for its production to date and anticipated recovery. This measure is closer in sense to a reserve.
The British Geographical Survey (BGS) in association with the Department of Energy and Climate Change (DECC) completed an estimate for the resources (gas in place) of shale gas in part of central Britain in an area between Wrexham and Blackpool in the west, and Nottingham and Scarborough in the east.34 The estimate is in the form of a range in order to reflect geological uncertainty. The lower limit of the range is 822 trillion cubic feet (tcf) and an upper limit of 2281 tcf, but the central estimate for the resource is 1329 tcf (see Figure 6).
This shale gas estimate is a resource figure and so represents the gas that is thought to be present, but not the gas that it might be possible to extract.
Prediction of reserves then needs to be considered against what can be economically recovered, which of course depends on the price of gas within the market it is operating in. The volumes of gas that can be actually recovered against the predicted reserves are very difficult to determine until exploratory wells have been drilled. While figures of between 10 and 20% of predicted reserves could be recoverable, in some instances the gas actually recovered has been very much lower.
In terms of estimates from individual licence areas that have already been allocated in the UK, four companies have provided estimates of reserves but to date only one company, Cuadrilla Resources, has carried out exploratory drilling. This exploration of the commercial shale gas extraction has taken place in the Bowland Shales in Lancashire. The company's UK Petroleum Exploration and Production Licence (PEDL) was granted in September 2008. (A PEDL is awarded for six years initially on the basis of the applicant demonstrating technical and financial competence and an awareness of the environmental issues. The licensee is also required to demonstrate that they have obtained access rights from relevant landowners and complied with other statutory planning laws).
Work commenced on site, drilling the first test well in August 2010 at Preese Hall Farm followed by a second at Grange Hill Farm later that same year. Work on the third, near the village of Banks, commenced in August 2011. Based on the initial exploration, Cuadrilla Resources announced its first estimate of the volume of shale gas within its licence area on 21st September 2011. It estimates the total gas initially in place to be 5660 billion cubic metres (bcm) of gas; if it were able to extract 20% of the gas this would equate to 1132 bcm of recoverable gas.
Island Gas Limited (IGL) and its subsidiary company IGas Resources PLC operate in the North of England and North Wales and, using borehole logs, they have identified shale deposits extending over 1195 km2 with an average depth of 250 m. In October 2010 they gave estimates of gas initially in place as between 2.5 bcm and 131 bcm, with a risk factor of 50% for their North Wales licence area. No estimates of recoverable gas have been given and they intend to conduct further exploratory work in the future to fully understand the potential of these deposits.35
Eden Energy Ltd commissioned an independent expert report from RPS Group plc, a multinational energy resources and environmental consultancy company, in respect of prospective gas reserves in the 806 km2 of the seven PEDLs in South Wales. They have estimated that the proven reserves of gas initially in place are 968 bcm, with recoverable volume of 362 bcm.
Dart Energy, which took over Composite Energy in 2011, has indicated shale potential in addition to coal-bed methane extraction within its licence area of north west England and Wales with an estimate of total gas initially in place of 34 bcm.36
In April 2012, Dart Energy completed the acquisition of Greenpark Energy's 17 UK licences. Of these licences, PEDL159 is the furthest developed and is situated in Scotland. Eight wells were drilled in the area by Greenpark Energy, with three of these wells being pilot production wells, which demonstrated good production rates of natural gas from the coal seams. The remaining five wells were exploration wells; these delineated seam thickness, gas contents, gas saturations and permeability trends in the area. Since the acquisition, Dart Energy has been assessing the licence area from both a sub-surface and surface perspective.
In total, Dart Energy now have four licences in Scotland and a further 28 licences in rest of the UK.
Shale gas production in the UK is still some years off, with production unlikely to start before 2015–2016. Estimates of production are still very difficult to obtain, but Cuadrilla have estimated that commercial development of the resource would provide an annual average of 0.7 to 2.8 bcm of gas. With cumulative estimates of between 19.7 and 76.7 bcm total gas production by 2040 based on the well construction figures for the Bowland shale shown in Table 5. This represents between 1.7 and 6.8% of the estimated 1132 bcm recoverable resource.
|Year||Well construction low||Well construction central||Well construction high|
|Wells per pad||10||10||10|
|Duration of activity (years)||6||9||16|
|Peak activity (wells drilled per year)||40||60||60|
The figures for possible maximum annual production of shale gas from projections relating to Cuadrilla and the Bowland shales of 4.90 bcm shown in Table 6 need to be set against the annual UK gas consumption in 2010 of 91 bcm.37
|Cumulative Production (bcm)||19.7||40.3||76.7|
|Cumulative as a percentage of estimated recoverable resource (1132 bcm)||1.7%||3.6%||6.8%|
|Average annual production (bcm)||0.73||1.49||2.84|
|Average annual production as a percentage of UK consumption in 2010 (91 bcm)||0.8%||1.7%||3.2%|
|Minimum production in a single year (bcm)||0.29||0.58||0.58|
|Maximum production in a single year (bcm)||2.12||3.57||4.90|
In terms of resource requirements, Table 7 provides information on the activities and resources required for development of shale gas pads in the US, where the resources for the vertical bore are separated from the resources associated with the horizontal bore and the hydraulic fracturing.15
|Activity||Six well pads drilled vertically to 2000 m and laterally to 1200 m|
|Construction||Well pad area (ha)||1.5||2|
|Cuttings volume (m3)||827|
|Hydraulic Fracturing||Water volume (m3)||54 000||174 000|
|Flowback fluid volume (m3)||7920||137 280|
|Surface Activity||Total duration of surface activities pre-production (days)||500||1500|
|Total truck visits||4315||6590|
|Re-fracturing Process Assuming an average of 50% of wells re-fractured only once||Water volume (m3)||27 000||87 000|
|Fracturing chemicals volume, @ 2% (m3)||540||1740|
|Flowback fluid volume (m3)||3960||68 640|
|Total duration of surface activities for re-fracturing (days)||200||490|
|Total truck visits for re-fracturing||2010||2975|
|Total for 50% re-fracturing||Well pad area (ha)||1.5||2|
|Cuttings volume (m3)||827|
|Water volume (m3)||81 000||261 000|
|Fracturing chemicals volume, @ 2% (m3)||1620||5220|
|Flowback fluid volume (m3)||11 880||205 920|
|Total duration of surface activities pre production (days)||700||1990|
|Total truck visits||6325||9565|
Based on the information from similar operations in the US shown in Table 7 and using the commercialisation scenarios from Table 5, it is possible to estimate the resource requirement under Cuadrilla Resources’ various scenarios (see Table 8).
|Resources use per well|
|Well pads||0.1 (i.e. 10 wells per pad)|
|Well pad area (ha)||0.7|
|Water volume (m3)||8399|
|Fracturing chemicals volume (m3)||3.7|
|Cuttings volume (m3)||138|
|Incorporating data from Table 7|
|Low Estimate||High Estimate|
|Flowback fluid volume (m3)||1232||6627|
|Total duration of surface activities pre production (days)||83||250|
|Total truck visits||719||1098|
As can be seen from Table 6, the high scenario involving the development of 810 wells will provide a cumulative volume of shale gas of 76.6 bcm over a 25-year timescale, with an annual production of 2.84 bcm. Therefore, to have a significant impact on the annual gas consumption in the UK, significantly more wells need to be developed in the UK as a whole.
To achieve a 10% production of UK annual gas consumption of 91 bcm would require of the order of 250 wells to be in production at any one time and, bearing in mind the productivity of individual wells over time decreases rapidly, the figure in reality would have to be considerably greater to take account of the decline in production, with new wells having to come online or existing wells re-fractured. Over a 20-year period, between 2600 and 3000 wells would need to be developed to deliver a sustained annual output of 9 bcm. This equates to between 260 and 300 well pads, assuming that 10 wells can be drilled and hydraulically fractured from each well pad.
To put this into context, the DECC in 2010 identified that only 2000 wells had been drilled in total in the UK, with about 25 onshore wells drilled per year in the UK in the last decade.
Based on the information from Cuadrilla and the US, Table 9 provides the total resources required in the UK for production of 9 bcm of shale gas, which represents 10% of the annual UK gas consumption in 2010.
|Assuming no re-fracturing||Assuming a single re-fracturing on 50% of wells (delivering an assumed 25% increase in productivity for those wells)|
|Cuttings volume (m3)||409 365||357 264|
|Water volume (m3)||24945030||32 655 312|
|Fracturing chemicals volume (m3)||10989||14 386|
|Flowback fluid volume (m3)||3 658 604||19 680 768||4 789 446||25 763 915|
|Total truck visits||2 135 925||3 262 050||2 732 400||4 132 080|
The UK at present gets its gas from a variety of sources, including the UK Continental Shelf (UKCS) where production has been in decline since 2000, and in 2012 it was 38% (43 bcm) of the level produced in 2000 (114 bcm). Since 2000 the rate has declined on average by about 8% per annum, but the decline varies each year depending on operational issues and the price of gas on the world market, which determines the viability of marginal production. In 2012 production was 14% lower than in 2011. This was largely due to operational issues where a leak on the Elgin platform in the North Sea in March 2012 reduced production for the rest of 2012.
The UK imports natural gas by pipelines from Norway, Belgium and the Netherlands, and liquefied natural gas (LNG) via ships. The UK has been a net importer of gas since 2004, with net imports in 2012 accounting for 47% of supply. In 2012 the UK imported approximately 50 bcm. In 2012 total LNG imports to the UK via the four import terminals at Dragon (Milford Haven), Isle of Grain, South Hook (Milford Haven) and Teesside GasPort were approximately 13.5 bcm (see Figure 7).36
With the two interconnecting pipes to mainland Europe, the UK gas network is integrated with the wider continental gas network, with gas pipelines extending into Russia, the Middle East and North Africa. These pipelines enable gas to be moved around from various locations internationally and enable the gas producers to buy and sell gas on the international market without the need to liquefy and ship it. This reduces costs and therefore ensures that the UK can not only import gas via pipelines from a wide geographical area but also allows UK producers to export UKCS gas to Europe.
It is against the background of international trade, which contrasts with the situation in the US that any shale gas production in the United Kingdom needs to be considered.
In North America, which has very limited export markets for the shale gas it produces, with pipelines extending into Mexico and no LNG export terminals, any shale gas produced is used predominantly within the US. This led to a dramatic reduction in the cost of gas within the US, with gas prices today (in 2013) at about a third of the peak energy price in 2008 (see Figure 8).
The US is now in the process of converting liquefied natural gas (LNG) import terminals into LNG export terminals. A recent deal between the BG Group and the US energy firm Cheniere Energy Inc. may allow 3.5 million tonnes per year of LNG to be exported from the US to Europe from 2015 onwards at prices lower than Asian or European gas.38 It will be interesting to see whether the exporting of LNG from the US to the world market will impact on the price of shale gas within the US and, more importantly for the UK, whether the price of gas falls. This will provide, for the first time, direct competition between US-produced shale gas and locally produced natural gas in Europe.
As of 1st October 2013, the US Department of Energy (DOE) has approved only four applications for permits to export LNG to non-free trade agreement nations. There are currently 21 pending applications, covering 19 facilities where US businesses are seeking to build and operate terminals to process LNG for export.39 The most recent decision was made in September 2013, when Dominion Resources Inc. received approval for the Cove Point Terminal on the Maryland shore of Chesapeake Bay. To date, the DOE has authorised 6.37 bcf of LNG from the plant to be sold overseas. Delays in the approval process stem from the debate within the US administration on how much natural gas should be exported without raising the natural gas prices and reducing supplies in the US.
As well as supplies of shale gas from America using LNG export terminals, Australia also plans to expand in the export market for LNG. It now accounts for 9% of the globally traded LNG and production is set to ramp up substantially (see Figure 9).
Investment in capacity to export LNG has been the key driver of Australia's recent boom, with 7 of the world's 12 largest LNG plants being built in Australia. Investment in Australia accounts for around two thirds of all the current global investment in the LNG industry.40 Exports are set to rise sharply and government forecasts suggest a rise of over 300% between 2015 and 2020.
Based on Australian government projections, Australia will become the second-largest exporter of LNG in the world by 2016. If all the major investments projects under consideration were to go ahead, Australia stands to become the world's largest exporter of LNG by 2020, overtaking Qatar. This is without the potential shale gas and other unconventional gas sources being heavily exploited. These developments are in their early stages but could become a significant source of the country's gas production, especially given that the LNG export capacity is already being built.
This expansion in the Australian LNG market will be in direct competition with the expansion of the US shale gas export proposals and will be competing for the same markets worldwide. It will be interesting to see how the expansion in exports of LNG affects the development of shale gas in other areas and the impact that this has on world gas prices. Should world prices reflect prices in the US, then it is likely that that there will be a slowing down of future exploration in countries where regulation and operating conditions are more challenging.
If, due to increases in the world gas demand (not only from developing countries but also as a result of a change in national policy relating to power generation in countries such as Japan and Germany), there is little impact on world gas prices, then shale gas extraction in other countries will continue to be developed. Japan and Germany are expanding their gas-fired power station programmes as a result of trying to reduce their nuclear generation capacity in response to the Fukushima nuclear accident that occurred in 2011.
Regulation in the UK is controlled by a variety of national and local government departments with a variety of different responsibilities.
In the UK, the environmental considerations are controlled by the following organisations: the Environmental Agency (EA) in England, the Scottish Environmental Protection Agency (SEPA) and the Environmental Agencies of Wales and Northern Ireland. These agencies are responsible for the protection of the environment and for the exploration and extraction of unconventional gases for which they perform various roles. The agencies provide advice to central government and regulate operators to ensure that the environment is protected. They also advise government on the sustainability of these sources of natural gas and their associated extraction technologies. The agencies ensure that the exploration and development of unconventional gases is regulated effectively to manage risks to surface water and groundwater resources. In addition, they are responsible for granting any necessary environmental permits and have powers to serve notices, where required, to protect the local environment.41 This is done by applying a proportionate and risk-based approach to preventing pollution and protecting the environment. The EA is responsible for regulating water abstraction and regulating any discharge associated with the extraction process and is also a statutory consultee in the planning process and will provide advice to local authorities on individual gas extraction sites.
The Department of Energy and Climate Change (DECC) administers the licensing system under the Petroleum Act 1998, which authorises each particular drilling as a development activity. DECC provides up-to-date information on its website relating to the various Approved Codes of Practice, official guidance and referenced codes, standards, etc., which need to be taken into account when proposing to develop a shale gas deposit.42
The Planning Authority (generally the local authority) deals with the planning application that is required for each site. The councillors who are responsible for approving these planning applications are locally elected representatives and as such are keenly aware of the local issues and the impact that these decisions will have on the local electorate.
The Health and Safety Executive (HSE) regulates the safety aspects of the work, which contributes to the mitigation of the environmental risk. In particular, they are responsible for regulating the appropriate design, construction and continued integrity of any gas well. In addition, the rest of the requirements under the Health and Safety at Work Act 1974 will also need to be considered when proposing and undertaking any works.
The Institution of Gas Engineers and Managers (IGEM) has published a guidance document, IGEM/G/101 on Onshore Natural Gas Extraction and Route to Use, which provides an overview of the requirements in the UK.43
Shale gas has not yet been developed on a commercial basis in the UK, which inevitably means that one has to make a series of assumptions about how successful the shale gas industry will become and the effect of shale gas on energy prices within the UK economic environment.
As many experts have identified, there are a number of barriers and issues about UK shale gas that are different from the situation applicable in the USA. These include different geology, different regulation and a much greater density of population. The experience of other European countries also highlights that, even within Europe, opinions relating to shale gas are divided. France, for example, currently has a moratorium on shale gas, whilst in Poland the government is actively supporting shale gas development although the industry faces various problems here that are affecting its development.
The US Energy Information Administration estimated in 2011 that Poland had possible reserves of 5.3 trillion cubic metres of shale gas, the biggest in Europe. More recently, the Polish Geographical Institute has been more conservative, with estimates of between 346 and 768 billion cubic metres of shale gas.44 However, there is a fear that Poland is moving to tax and regulate the shale gas industry more and this uncertainty, coupled with the complicated geology, which has produced some disappointing early results from test wells, has lowered the enthusiasm of international exploration companies.
So the development of shale gas across the UK and the rest of Europe is a mixed and complicated prospect that is difficult to predict, both in terms of the volumes likely to be extracted and the impact this will have on overall energy prices.
Worldwide predictions get even more difficult. The US Energy Information Administration published figures in 2013 of the technically recoverable shale gas resources outside of the United States which identified China as having reserves of 31.55 trillion cubic metres and the top ten countries, which include the US, as having reserves of 206 trillion cubic metres (see Table 10).48 However, how much of these reserves are economically recoverable is another matter. Key positive above-the-ground advantages in the US and Canada that may not apply in other locations include private ownership of sub-surface rights that provide a strong incentive for development. These include the availability of many independent operators and supporting contractors with critical expertise and suitable drilling rigs and the pre-existing gathering pipeline infrastructure, together with the availability of water resources for use in the hydraulic fracturing.
|Rank||Country||Shale gas reserves (trillion cubic metres)|
|World Total||206.56 (220.6)|
|a Energy Information Agency estimates used for ranking order. Advanced Resources International estimates in parentheses.|
Given the variation across the world's shale formations in both geology and above-ground conditions, the extent to which global technically recoverable shale resources will prove to be economically recoverable is not yet clear.
The impact that shale gas will have on the UK gas supply situation and the price to gas customers is impossible to determine due to the large amount of uncertainty.
Lord Browne, one of the most powerful energy figures in the UK and Chairman of Cuadrilla, the leading shale gas company in the UK, told an audience at the Grantham Research Institute at the London School of Economics (LSE) on the 27th November 2013,
“I don’t know what the contribution of shale gas will be to the energy mix of the UK. We need to drill probably 10 to 12 wells and test them and it needs to be done as quickly as possible.
“We are part of a well-connected European market and unless it is a gigantic amount of gas, it is not going to have a material impact on price.”45
These two sentences effectively sum up the situation within the UK at this time (December 2013).
The views expressed in this chapter are those of the author and do not necessarily reflect the position or policy of the Institution of Gas Engineers and Managers.
© The Royal Society of Chemistry 2015 (2014)