Expert Scientific Panel on Unconventional Oil and Gas report

Chapter 3 - The Current Industry

Coal Bed Methane

A brief history of coal bed methane developments worldwide

3.1. Methane associated with coal-bearing strata was initially encountered and dealt with as a safety hazard in active coal mines. Some of the earliest historical accounts of 'firedamp', which is the flammable mixture of methane and air found in many mines, were in Scottish coalfields.

3.2. Although Scottish coal-bearing strata would not generally be considered "gassy" by later UK and global standards ( DECC 2010), methane was certainly present in sufficient abundance to give rise to explosions. In many cases, there was loss of life, such as at High Blantyre in 1877 (207 killed) and Udston (Hamilton) in 1887 (73 killed) ( NCB, 1958).

3.3. As safety standards in Scotland's collieries improved, active methane drainage schemes became commonplace ( NCB, 1958). Indeed, several large collieries installed methane capture and use systems, providing some of the power needed to operate mining machinery.

3.4. These experiences, accompanied by those in conventional oil and gas operations offshore, resulted in widespread acknowledgment of how methane can be handled safely, and the conversion of UK domestic gas supplies to North Sea gas in the 1970s provided further familiarity.

3.5. Scotland was an early entrant into the exploitation of gas from active mines. For instance, at Cardowan Colliery, the Dumbreck Cloven seam had 3.6 m ³/tonne gas, and the Kilsyth coking seam 4.9 m ³/tonne gas, which was sold commercially from 1972 - 1982. Despite early involvement, Scotland has not participated in the 'abandoned mine methane' industry. This industry is well developed in the coalfields of the English Midlands by Alkane Energy plc for instance ( DTI, 2001; Jardine et al,. 2009).

3.6. Commercial interests in Scotland's potential coal bed methane ( CBM) industry are currently small. This can partly be attributed to the availability of abundant North Sea gas over the last three decades. It is important to note that CBM involves only the extraction of pre-existing methane from coal seams. It does not involve conversion of the coal itself into methane.

3.7. Large-scale implementation of CBM was pioneered in the USA. It was originally developed as a form of advance methane drainage prior to deep mining in the Black Warrior Coal Basin, Alabama, in the 1970s. Together with the laterally equivalent North Appalachia Basin; the Powder River Basin in Wyoming; and the San Juan Basin in Colorado, these now account for more than half of the 2.8 trillion m ³ (100 tcf) of recoverable CBM resources in the USA (Halliburton 2009).

3.8. Although recoverable CBM resources in the world are not well characterised, it is conservatively estimated that global CBM resources amount to at least 33.98 trillion m ³ (1,200 tcf), with particularly substantial resources in Canada, Russia, China and Australia (Sloss, 2005).

CBM Technology: evolution and state-of-the-art

3.9. CBM extraction is achieved using boreholes drilled from surface, as follows:

(i) Identify target coal seams using geological exploration methods and previous borehole, gas and oil production, information, typical to the industry;
(ii) Drill two or more boreholes into the target seam, and a few metres below to create 'sumps' beneath the seam floor level. These boreholes should be thoroughly sealed-off (by means of steel casing cemented into place) from the strata overlying the coal seam: only the target coal seam is open to the borehole. Several of these bores are likely to be deviated, to run horizontally along the coal seams, in order to carry maximum gas to the vertical production borehole;
(iii) Install pumps with very high lift capabilities into the borehole sumps;
(iv) Pump the boreholes to de-pressurise groundwater in the coal seam until the head of water (height of water column supported by pressure at the base of the borehole) in the borehole drops below the threshold that allows mobilisation of desorbed gas into it. Unlike in many conventional oil and gas reservoirs (where the gas will be at a sufficiently high pressure to bubble through a much larger head of water in the borehole) in CBM fields pumping usually has to be maintained until the water level has dropped below the seam floor level before the bulk of the methane will enter the borehole. This is the reason why overlying strata are thoroughly cased-out in CBM operations, as otherwise more groundwater than necessary would need to be pumped from great depth. Gas initially moves from microscopic pores in the coal, and subsequently degasses from dissolution in the groundwater. Gas travels to the borehole along the face cleat (dominant fractures in the coal). Thus, when deviated horizontal boreholes are used, these are oriented to run perpendicular to the face cleat, thereby encouraging maximum flow of gas into the borehole;
(v) Collect the gas moving into to the boreholes and dispatch it to surface facilities for processing and use;
(vi) Dispose of the pumped water (production water), either to sewer or surface water (following any required treatment) or by reinjection.

3.10. These steps are common to all CBM operations. In many cases, the native permeability of the coal seam will prove to be too low, and either or both of the following 'stimulation' techniques may also be applied:

(i) Direct borehole linking, by means of within-seam directional drilling, which ensures far more of the natural small cracks in the coal are exposed to the borehole wall;
(ii) Hydraulic (or other) fracturing of the coal seam to increase permeable flow.

3.11. While a simple fracturing process to increase permeability was carried out on vertical boreholes during early exploration of CBM in Airth in the mid-1990s (see 3.14 for more detail), none of the coals appraised for commercial-scale CBM in Scotland to date should require hydraulic fracturing of the horizontal borehole. This is due to their distinctive physical properties compared to those found in other continents.

3.12. In recent years, several mature CBM fields in other continents have been subjected to injection of CO _2, which has routinely been used as an agent to increase production from mature oil wells (so called CO ₂-enhanced oil recovery). In CBM production, injected CO ₂ preferentially binds to coal surfaces and actively displaces residual methane to the production boreholes. This approach has been applied with considerable success in the Bowen Basin in Australia for instance ( e.g. Golding et al. 2011) and is referred to as enhanced coalbed methane recovery (ECBM) ( DTI 2001).

Recent and current CBM activity in Scotland

3.13. To date, preliminary investigations have been undertaken at five locations in Scotland (summarised in Table 3.1). However, only two CBM fields have been explored in any detail, and only one has proceeded to pilot testing for gas production.

Table 3.1 - Summary of Coalbed Methane Site Investigations in Scotland, 1993 - 2014

Licence ( PEDL) no.	Site	Company	Comments
133	Airth	Composite Energy / Dart Energy	15 boreholes have been drilled and some pilot gas production successfully achieved. For further detail see Section 3.14 below.
159	Canonbie	Greenpark / Dart Energy	8 boreholes have been drilled, but no gas production has yet been undertaken. For further detail see Section 3.15 below.
161	East Fife	Composite Energy / Dart Energy	A single exploration well was drilled by Composite Energy prior to their acquisition by Dart Energy in 2012. 10km of seismic line data are being assessed together with the well data before any further proposals are made.
162	Lanarkshire	Reach Coal Seam Gas	An initial proposal to drill near Moodiesburn was withdrawn in early 2012 after more than 200 objections were lodged. The company has planning permission for a gas exploration and production facility to extract coalbed methane at Deerdykes, Cumbernauld. A CAR authorisation for the construction of one investigatory borehole at the Deerdykes site has been issued by SEPA.
163	West Fife	Composite Energy / Dart Energy	A single exploration well was drilled by Composite Energy prior to their acquisition by Dart Energy in 2012. 10km of seismic line data are being assessed together with the well data before any further proposals are made.

3.14. Composite Energy / Dart, Airth PEDL 133 - Historical analysis

• Exploration initiated by Hillfarm Coal Company in 1993;
• Assessment of old records showed that the methane content in the Cloven and Kilsyth seams at Cardowan Colliery varied between 3.6 - 4.9 m ³/tonne (Bacon 1995). Other National Coal Board data had indicated low gas contents in the overlying Upper Limestone Group and Coal Measures (Creedy 1991);
• The first well was drilled at Airth (No 1) and accessed the Bannockburn seams, which proved to have high methane contents (8-10 m ³/tonne) and a fracturing process increased the permeability to 25 millidarcy (mD);
• Gas production from Airth No 1 began at 1.7 million m ³/day (60 million cubic feet per day - mcfd) in January 1994, later declining to 170,000 m ³/day (6 mcfd), and rose again to 0.99 million m ³/day (35 mcfd) in 1995 (Bacon 1995). Water co-production rates initially reached 42.5 m ³/day (260 barrels per day), declining to 4.9 m ³/day (30 barrels per day) by 1995 during gas production (Bacon 1995);
• Coalbed Methane Ltd took over the PEDL by 1996, and drilled Airth 2, 3 and 4 wells - their gas production rates are unknown, but a water production rate of 8m ³/day (50 barrels per day) was noted in 2001;
• Composite Energy had taken over Coalbed Methane's interests by 2004, drilling Airth boreholes 5 to 11 by 2007, with horizontal completions;
• Dart Energy acquired the PEDL in 2011, by which time a total of 15 wells had been drilled, with small scale gas production;
• In August 2012, Dart Energy submitted its planning application for the Airth coal bed methane development to Falkirk and Stirling Councils. The application went to planning inquiry during March 2014. The outcome is unknown at the time of writing.

3.15. Greenpark/Dart Energy, Canonbie PEDL 159 - Historical analysis

• The coalfield within the PEDL 159 area was known to have high gas contents from ten boreholes drilled between 1955 and 1983 by the National Coal Board (later British Coal). Records for these boreholes are held by BGS;
• A large subsurface area, between the Scottish and Cumbrian outcrop areas of the coalfield has never been mined;
• Greenpark-Marathon conducted exploration at the site, drilling 8 wells before April 2012. 18 additional borehole sites are already permitted;
• Two of the former Greenpark licences issued by SEPA allowed for "the injection of fracking fluids into groundwater" in coal seams at Mouldyhills and Broadmeadows, using laterals drilled into 5 individual seams. The plan was to use nitrogen foam frack (70% by volume nitrogen gas) rather than water, at an operating pressure of 17 MPa at depths between 560 and 1020 metres below ground, with microseismic monitoring to check no fracture propagation reached overlying aquifers. These fracking operations were never implemented;
• Dart Energy Ltd acquired the licences in 2012 and are proposing development without fracking, along the same lines as their Airth operations.

Economics of CBM nationally and internationally

3.16. The economics of CBM do not differ notably from those of any other source of natural gas. The market price for gas, weighed against the costs of exploration, development and production, determine whether and when a given CBM prospect becomes economically viable. To date, natural gas prices have not been subject to global trading in the way that oil is, mainly due to the costs of inter-continental transport ( e.g. in tankers as LNG).

3.17. Therefore, natural gas continues to be traded in regional markets with distinct prices. It has been suggested that this system may soon break down, if the projected scale of the 'shale gas revolution' in the USA is realised over the next decade or so, with large-scale LNG exports from the USA across the Pacific and Atlantic oceans. However, this is still subject to much debate (Rogers, 2011; Martin, 2013).

3.18. The development of the US shale gas industry is depressing the price of coal (which is globally traded) as US producers export coal at very low prices. This means that substantial Scottish coal reserves that were considered to be reasonable prospects for new opencast (or even deep mine) developments as recently as the first quarter of 2013 are now rendered uneconomic. The identical effect in April 2014 is also forcing closure of the remaining English coal mines. The effect is that - ignoring emissions or environmental costs - coal has become a low cost fuel, whereas gas in the UK has increased in price to become the higher cost fuel.

3.19. However, factoring in emissions and environmental costs, the use of coal for electricity generation should become less attractive as a result of UK regulations that require new coal plant to be fitted with CCS technology. Conversely, gas is preferred by a UK Treasury policy that new gas plant need not fit CCS, and is less penalised by a carbon base price in the UK electricity market.

3.20. The overall effect is that UK shale gas will not be exploited unless it is cheaper than imported gas. Further, it is unlikely to be exploited until the use of cheap imported coal is curtailed through enforcement of existing requirements that coal-fired power plants have their emissions abated in future by means of carbon capture and storage. This may have the effect of making coal-fired electricity generation relatively more expensive that using gas for electricity production.

Shale Gas and Shale Oil

A brief history of shale gas and shale oil worldwide

3.21. The world's first industrial-scale hydrocarbons industry was in Scotland, exploiting organic-rich shales which are now regarded as desirable shale gas prospects. Organic material is present in sedimentary rocks that, when heated naturally in the Earth's crust, breaks down into petroleum and natural gas. The historic industry in Scotland involved conventional mining of the shales, with any trapped gas being vented to the atmosphere, and subsequent retorting of the run-of-mine product to derive paraffins and related liquid hydrocarbons (Carruthers et al. 1927; McKay, 2012), with the burnt waste rock being tipped to form the distinctive pink bings of West Lothian.

3.22. There does not seem to be any realistic scenario for a resumption of oil production from Scottish oil shales by the historic methods of mining and retorting the shales at surface. The mined rock masses themselves are no longer shale gas prospects either. This is because the mining left behind networks of highly interconnected and largely flooded old mine workings, which long since de-gassed the uppermost few hundred metres of the shale sequences they penetrated. It is therefore more likely that unmined portions of these horizons deeper underground could be targeted for future shale gas development: there would be no incentive to explore for shale gas in close proximity to old mine workings.

3.23. Scotland has had very little onshore conventional hydrocarbon production. The first gas discovery in Scotland was British Petroleum's borehole in the Salsburgh anticline in 1944, which reportedly flowed at 934 m ³/day (33,000 cubic feet/day) from the Strathclyde Group (which is now encompassed within PEDL 162). The commercial field at Cousland operated from 1957 - 1965 and a gas well was completed at Bargeddie in 1989, reportedly flowing at 11,327 m ³/day (0.4 million cubic feet/day) of gas - however, this field was not developed.

Technology used currently

3.24. The exploitation procedure for shale gas differs from that of CBM. It is probable that Scottish geology hosts several different types of shale containing gas (further discussed in Chapter 4). Additionally, Scotland certainly hosts a type of shale which can produce oil directly. Although widespread globally (World Energy Council 2010), oil shale deposits similar to those in Scotland have not yet been widely exploited by drilling, but by mining. The exception to this is the oil shales of the eastern Baltic States, though exploitation of those deposits declined markedly following the transition to a market economy. The much-discussed Athabascan tar sands of Canada are geologically dissimilar to Scottish oil shales.

3.25. Shale strata similar (although not identical) to the Lothian oil shales are increasingly being exploited as shale gas prospects by means of boreholes drilled from surface. This is the approach taken in many parts of North America, and prospects for similar activity are increasing elsewhere.

3.26. In summary, the shale gas or shale oil exploitation process is as follows:

(i) Identify target shale sequences using conventional geological exploration methods;
(ii) Drill boreholes into the target sequence, carefully installing hollow steel casing to support the borehole, and to prevent contamination of shallower porous aquifers by drilling or formations waters, or gas produced from depth. The casing must have a gas-tight bond by cementing to the surrounding rock casing and cementing them out above the target sequence;
(iii) Undertake hydraulic fracturing (fracking), using batteries of pumps at surface, inject water (with around 5% of additives, being mainly sand grains) at pressures carefully calculated to overcome the yield strength of the shales, so that they either open up pre-existing fractures or create new ones. Additives are typically 5% sand "proppant", to physically keep the fractures open, and 0.1 - 0.2% chemicals to enhance water flow and inhibit unwanted bacterial growth;
(iv) Pump the injected water plus any admixed native groundwater (likely to be scarce in shales; Younger 2007) back to surface, until such time as the level of water in the borehole drops below the threshold that allows gas to overcome the water pressure and move from the pores of the shale into the borehole;
(v) Collect the gas or oil moving to the boreholes and dispatch it to surface facilities for processing and use;
(vi) Dispose of the pumped water, either to sewer or surface watercourses (following any required treatment), or else by reinjection to the subsurface.

3.27. To ensure continued gas production, steps (iii) through (vi) may need to be repeated over the years, until all the economically recoverable gas has been extracted. In principle, injection of CO ₂ could help displace further methane into the production boreholes (in a manner similar to ECBM), though this requires specific borehole layouts and proximities that are less common in shale gas operations than they are in CBM.

3.28. Some - but by no means all - shale gas operations also yield appreciable quantities of oil. It is not yet clear whether any such possibility of shale oil production exists in Scotland.

Economics of shale gas nationally and internationally

3.29. The principles of CBM economics apply equally here: gas or oil produced from shale using the above approach must compete in the respective regional (gas) and global (oil) markets. The market costs of these commodities will determine whether the costs of exploration, development and production are justifiable.

3.30. As Scotland has very little onshore hydrocarbon exploration and development activity, drilling costs will be higher compared to North America, but could decrease if a larger market encouraged companies to make more equipment and labour available. However, if the postulated globalisation of gas markets does occur (Rogers, 2011; Martin, 2013), it may well result in Scottish deposits being left undeveloped for the foreseeable future, as existing production costs would likely remain uncompetitive internationally.

3.31. The impact of US shale gas on the price of coal (which is globally traded) is now being felt in Europe (Rogers 2011). This does not necessarily mean that less coal will be used however, as cheap imports simply displace locally produced coal. Low prices could also increase the use of coal over other types of energy resource.

Challenges for Scotland

3.32. Most of Scotland's onshore coal bed methane and shale gas resources occur in and around the former coalfields and oil shale fields, which remain amongst the most densely-populated parts of the country. Any industrial development in a densely-populated area will face significant challenges, and unconventional gas will be no exception to this. Exploration and development of gas shales in North-East Scotland or in the Inner Hebrides would be in sparsely populated regions - where local employment opportunities during shale gas operations could mean different public attitudes. It is possibly helpful to identify what is technically different or distinctive about shale gas drilling, compared to routinely accepted types of onshore drilling.

3.33. Contentious issues are likely to include truck movements, temporary visual impact during drilling and any other issues typically arising due to proximity of long-term plant to other properties. These issues apply to many other industrial developments, of course. Truck movements could be minimised where water supply can be obtained from the public water mains, or by a licensed abstraction from a nearby waterbody.

3.34. It is increasingly common practice in the US for shale gas pads to host multiple wells (National Petroleum Council , 2011). Multiple well heads are spaced a few meters apart on a single well pad. In addition each well could have multiple or stacked "laterals". Laterals are subhorizontal wells deviated from the main wellbore in multiple directions at the same level. Stacked horizontal wells target rock formations at different depths, either because the unit is very thick, or because there are multiple, stacked target horizons. This kind of multi-well, multi-lateral pad accesses a larger volume of rock for a roughly equivalent surface footprint (and reduced cost) (Husain, et al. 2011).

3.35. There has been public concern about the number of wells required to access UK unconventional gas resources, given that the UK has a much higher population density than much of the USA. Because multi-well, multi-lateral pads service a larger volume of rock, they will require larger volumes of water and other supplies to be delivered and wastes to be shipped out of a single pad. Higher volumes could result in significant economies of scale that may address some of the publics' concerns. For instance, the point at which is becomes more economical to develop a water pipeline rather than to have water delivered by truck is dependent on the volume of water. Multi-well, multi-lateral pads may encourage the use of water pipelines over tanker delivery, with the benefit of reducing the risk of road traffic accidents and the visual, noise and pollution disturbance of truck traffic.

3.36. Noise is frequently mentioned as a potential impact. However, modern deep drilling in the UK produces little external noise, and that noise is specifically regulated and enforced by planning consents. Acoustic insulation technology has long since been developed to ensure noise levels from drilling comply with strict limits imposed by planning authorities. On modern drilling rigs, even rig-hands do not need to wear ear protection. Recent experiences in northern England (Younger 2013) of deep geothermal drilling using rigs previously used for CBM and shale gas operations demonstrate that it is feasible to undertake deep drilling and associated activities in close proximity to housing with no breaches of strict planning conditions. The issue of noise with respect to environmental impact is discussed in greater detail in Chapter 6.

3.37. Hydraulic fracturing operations involve the use of multiple pumps to inject and pump back fluids. Again, the potential for noise from these operations has already been rendered compatible with planning conditions by use of acoustic insulation. This is exemplified by an established UK-wide industry that already undertakes 24-7 pumping of groundwater on a temporary basis - i.e. the construction dewatering sector: it requires all pumps to be acoustically insulated within housings that are sufficiently effective that no-one on site needs to wear ear protection, except for the engine maintenance technicians who occasionally access the interiors of the housings.

3.38. Concerns over the safety of methane handling are also routinely managed for other cases: 82% of Scotland's households are connected to the gas grid and use methane daily for domestic purposes (such as heating and cooking). As for gas wells themselves, safety procedures to prevent uncontrolled gas emissions are already stringent for purposes of workforce protection - this inherently safeguards the public who are further away from wellheads. There is an existing regulatory control over practises such as deliberate venting of methane, flaring of waste products, stripping out associated CO ₂, or monitoring and control of unwanted seepage from boreholes.

3.39. Exploitation of unconventional gas onshore will also be constrained by practical issues, such as proximity to gas transmission pipelines or end-user premises such as the Grangemouth complex. Connecting gas sources into such infrastructure is likely to require at least some additional pipe-laying, which will entail negotiating wayleaves and planning permission.

3.40. Supply chain constraints may also act as a brake on unconventional gas development, as the UK (and northwest Europe more generally) is not well supplied with suitable onshore drilling rigs and suitably qualified and experienced rig crews. Although much of the required borehole hardware is also used offshore and is readily available from existing suppliers, most of these suppliers are based in the Aberdeen area, so delivery times and costs may be an issue for development sites in the Central Belt. Typically the UK has fewer than 10 (usually fewer than 5) rigs and crews available to undertake shale gas drilling. That contrasts with the USA, where up to 500 rigs with crews exist.

Conclusions

• By comparison with international precedents of coalbed methane and shale gas development, and considering Scotland's former coal mining and oil shale industries, it seems likely that unconventional gas could be developed in the country at a significant scale;
• None of the required technologies are particularly new, albeit they have yet to be applied at full-scale onshore in Scotland for these particular purposes. To date, there has been preliminary, exploratory drilling, for coal bed methane only, at only two sites (with a third under consideration), and pilot production at only one site (Airth). No full-scale commercial operations are yet underway in the UK, or globally;
• The economic viability of unconventional gas in Scotland will be inextricably linked into the regional price of gas in the north-western European market. If the USA begins to export gas at large scale in future, this price may be depressed, making it less profitable to exploit Scottish resources;
• The high population density of those parts of Scotland most likely to host significant onshore unconventional gas resources would be a challenge for any form of re-industrialisation, and will thus be so for a future unconventional gas industry;
• Experience of onshore drilling elsewhere in the UK, and of the largely safe, routine management of gas throughout urban Scotland, suggests that none of the particular issues raised by unconventional gas developments would be insurmountable, given adequate planning and effective regulation.