Expert Scientific Panel on Unconventional Oil and Gas report
A report published on behalf of the Expert Scientific Panel on Unconventional Oil and Gas, which reviews the available scientific evidence.
Chapter 5 - Technical challenges
5.1 The Expert Scientific Panel has identified the following technological areas that pose important challenges in carrying out shale gas and coal bed methane recovery.
- Hydraulic Fracturing;
- Well Integrity;
- Gas Production;
- Water Sourcing;
- Wastewater Disposal;
- Well Abandonment.
5.2 An outline of the main technical challenges is given with comment on their cause, how they are currently tackled and their implications.
5.3 Once a gas prospect is identified, a well must be drilled to assess gas content and determine how readily it can be produced. In the early days of the oil industry, wells were almost entirely vertical. Wells are cased with metal tubes and the space between the tube and the drilled hole in the rock is cemented all the way down to the reservoir.
5.4 In the cased and cemented zone, it is critical that there is no flow between the wellbore and the surrounding rock, since leakage into the surrounding rock strata is undesirable. This is especially true in the shallower subsurface, where such leaks could potentially contaminate any freshwater aquifers traversed by the boreholes.
5.5 In the reservoir zone, i.e. in the coal for CBM or the shale for shale gas, the well is "completed" such that flow between the reservoir and the wellbore takes place. Most wells into shale gas and CBM formations are horizontal, in that the well is drilled vertically to a depth some distance above the reservoir and then steered to gradually follow the horizontal direction of the gas-bearing strata. The horizontal section of these wells are often 1 to 3 km in length which allows contact with a larger amount of reservoir rock than vertical wells, thus increasing gas production.
5.6 Drilling presents a number of technical challenges. Hard rocks, such as sandstone, are more difficult to drill through and therefore the hole is drilled more slowly and uses more drill bits. However, the final hole is stable and generally does not collapse. Softer rock, such as shale and coal, are much easier to drill but holes are more liable to collapse due to the low strength (as measured by uniaxial compressive strength). Borehole stability - not least during shale gas drilling - is well understood, and modern drilling, well completion techniques and drilling fluids have rendered it a relatively small problem.
5.7 According to the US Department of Energy (2013), around 2 million oil and gas wells in North America had been hydraulically fractured by 2013. Despite this, the design and execution of the hydraulic fracturing in shale reservoirs remains a technical challenge - the main objective being to yield the maximum amount of gas over a reasonable time with the fewest hydraulic fracturing jobs.
5.8 The process of hydraulic fracturing is broadly understood and models exist to design such jobs, while extensive oil industry experience exists in carrying them out. However, the process is not quantitatively predictable.
5.9 Hydraulic fracturing is typically carried out in a number of steps, as described in Chapter 3. Treatments vary in response to factors such as reservoir thickness, depth below the surface and mechanical properties. This involves designing the volume, the applied pressure and the specification of fluid.
5.10 The technical challenge is to design optimal "fracking jobs" so that the operation produces as much gas as possible from a single fracture treatment. The process is typically monitored by acoustic techniques. There is extensive industrial experience of how to control the process and maximise gas production.
5.11 The success of fracking in relation to the formation of the fractures in the rock depends on some shale properties, such as the brittleness. This in turn may depend on the sand content of the shale, relative to clay. These factors affect how easily and extensively the shale fractures. If productive shales are discovered in Scotland, then precisely how these are optimally fractured must be established. Despite decades of industry experience, the details of the fracture pattern and placement are not yet accurately predictable.
5.12 The consequences of sub-optimal fracking will be that wells do not produce as much gas as possible. This could lead to re-fracking operations earlier than had been anticipated.
5.13 When wells are fractured, the rock breaks and causes small locally detectable, acoustic (seismic) events. The fracking process induces many small local seismic events in the rock. These micro-seismic events cannot be detected with conventional equipment used for earthquake detection. However, downhole micro-seismometers or local arrays of sensitive micro-seismic detectors on the surface above the fracking location are used to detect and map the distribution of seismic events in 3D in order to direct and monitor the fracturing process.
5.14 The shales and surrounding rocks are under natural stresses and the hydraulic fracturing may trigger their release. Two earthquakes measuring 1.7 and 2.3 M L on the Richter scale were induced during fracturing operations by Cuadrilla in North-West England in April and May 2011. However, because the Richter scale is a logarithmic measure of magnitude, rather than a linear scale, the energy released by the 2.3 M L event was actually 4 times greater than the 1.7 M L earthquake. These events are most likely to have occurred on a pre-existing geological fault that was already close to slipping (Green et al, 2012).
5.15 These events are significantly smaller than the natural seismicity of the region. The largest recent event occurred in 2009 and measured 3.7 M L. This caused no damage to property or to the safety of local population. The British Geological Survey seismic network does not usually detect magnitudes below 2.5 in urban areas due to the background vibrations from traffic.
5.16 The technical challenge to avoid larger seismic events depends on:
- developing a good knowledge of the direction of existing principal stress fields in shale formations;
- knowledge of the mechanical properties of the shale and surrounding rock;
- mapping the positions of pre-existing faults, and their relationship to the applied stress ( i.e. how close they are to failure).
5.17 This is precisely the same information required to carry out efficient fracturing operations, and there is a clear incentive to gather these data in order to optimise hydraulic fracture design (see above). In the early stages of exploration and appraisal, such data may be unavailable. The monitoring of micro-seismic events during fracturing operations may eventually determine how best practice (in terms of both avoiding larger seismic events and optimising fracking design) is established.
5.18 Stress-release seismic events occur in "near critical" systems, which are not intrinsically predictable. For example, the relationship between magnitude and frequency of earthquakes is established for most seismically active regions. However, they cannot predict where or when earthquakes will occur. The low energy seismic events arising from hydraulic fracturing do not pose the same danger to human life as major earthquakes. For example, an earthquake measuring 5 - 6 M L on the Richter Scale would cause some damage to poorly constructed buildings with a relatively low number of potential casualties. However, this would have about 4,000 times greater energy than the larger of the two fracking-induced earthquakes in NW England in 2013.
5.19 Well integrity is important to ensure that no gas leakage occurs during production, or injected fluid leakage during the injection period of the hydraulic fracturing operation. The well is lined ( i.e. cemented and cased as described previously) throughout its entire length and is completed (where flow can occur between the rock/coal/shale and the wellbore) in the reservoir section ( Figure 5.1). Clearly the reservoir section has to "flow" in order to produce gas, but exchange between the main surface to reservoir section of the well should not flow (see Paragraph 5.4 above).
Figure 5.1: Scale drawing of shale gas and coalbed methane wells (black lines) coming from a stacked multi-well, multi-lateral well pad. Drill rig is about 10 m tall, note that a workover rig could be up to 20 m tall. Image of the 110 m high Forth Rail Bridge from 1911 Encyclopedia Britannica (licenced under Creative Commons) is provided for scale. The width of the black lines representing the wellbores in this image are wider than the wellbores would be at this scale - the diameter of the production casing is typically of the order of 14cm. Note that the geology is deliberately simplified: in the Central Belt prospective shale units are 2 - 3m thick and packaged within thicker interlayered units of "sandstones and shales" (Monaghan, 2013, Underhill et al., 2008). The details of the geology of other prospective areas in Scotland will remain unclear until such time as any exploration drilling takes place. The inset shows a typical well design (after Mair et al, 2012). Conductor casing is set for a depth of approximately 30 metres to stabilize the hole. The surface casing runs from the surface to beyond the lowest freshwater-bearing rocks. The intermediate casing isolates the borehole from non-freshwater zones. The production casing runs all the way to the production zone. At each stage cement is pumped into the wellbore and up between the casing and the rock until it reaches the surface. Geophysical tools are run down the hole to test for cement integrity before the next wellbore is drilled and cased. Horizontal wells for CBM will typically be at shallower depths (about 1 km) than shale gas wells (about 2 km), as shown in the diagram.
5.20 Poor well construction could lead to gas leakage into groundwater. There is evidence to suggest that gas leakage may have occurred during operations in the Marcellus Shale in the United States, where methane enrichments have been observed in aquifers within 1 km of wells (Jackson et al. 2013). However, detailed gas chemistry and isotopic analysis is required to establish whether these enrichments exceed natural background levels (Molofsky et al. 2011). It is important to note that virtually zero emissions of methane are technically achievable using best practice well construction and gas monitoring methods. There is no evidence to suggest that leakage of fracking fluids has led to increased levels of chemicals, salts, metals or radioactivity in near-well groundwaters ( e.g. Warner et al. 2012).
5.21 The prediction of the precise amount of gas that can be produced from a well is difficult. Estimates are often made by gas reservoir engineers by comparing the reservoir with analogues (for example, similar ancient sedimentary rocks that crop out on the Earth's surface and are much easier to study). Typically gas production is matched using models, then used to predict future treatments. However, the main objective from an operational point of view is that the level of gas production over the period is at an economic volumetric flow rate.
5.22 The consequences of poor prediction of gas production are mainly economic. If the predictions are too optimistic, then operators will not make as much money as anticipated - and more frequent fracking treatments will be required. If the gas volume is under-predicted and more gas is produced than anticipated, then the design of the production facilities may not be optimal and issues, such as water handling capacity, may ultimately affect production levels. If more fracking treatments than anticipated are required, this may also have environmental consequences, such as increased traffic and noise levels.
5.23 During the early period of a shale gas operation, the flow-back produces a significant amount of water, much of which was injected in the fracking operation. This interferes with the production of gas. After a period of injected water production, the gas production rises to a peak. This is followed by a period of declining gas production, during which the gas flow rate gradually reduces to an uneconomic level. This occurs since the gas in the formation (which can flow to the induced fractures) has depleted and gas from further away takes longer and comes at a lower flow rate.
5.24 Normal CBM extraction methods do not require significant volumes of water during drilling or extraction. In contrast, hydraulic fracturing requires large volumes of water. The volume of water required depends on a number of factors, such as reservoir geology, well depth, well length and the number of fracturing stages. Typically 40,000 - 300,000 gallons (180,000 - 1.36 million litres) of water may be required to fracture one well in a coal bed formation, while 2 to 4 million gallons (9.1 - 18.2 million litres) of water may be necessary to fracture a horizontal well in a shale.
5.25 Onshore operations typically use either mains water, or water abstracted from surface reservoirs or shallow aquifers. The water is required intermittently, usually during the drilling and fracturing stages of operation. Strategies can be employed to avoid water stress, such as scheduling operations to avoid periods when water supplies are low and by using alternative sources, e.g. seawater (Harris and van Batenburg 1999) or saline water from deep aquifers (Yost 2011). Current CBM operations in Scotland do not appear to need hydraulic fracturing, thus water requirements would likely be modest and could be provided via existing underground water mains pipes.
5.26 Water injection for hydraulic fracturing of shales results in the production of significantly more wastewater than CBM extraction. Typically 25 - 75% of the water injected during hydraulic fracturing returns to the surface during gas production - typically 0.5 - 3 million gallons (2.3 - 13.6 million litres). The volume of returned water depends on shale geology, type of fracturing fluid and the fracture design.
5.27 Hydraulic fracturing fluid usually includes between three and twelve chemicals depending on the characteristics of the water and the shale being fractured. Each component serves a specific purpose. A table of additive type, main chemical compounds and common use for hydraulic fracturing has been published by the United States Department of Energy ( US DOE, 2009). The chemicals used during hydraulic fracturing are typically at low concentrations (0.1 to 0.5%).
5.28 The water produced during CBM extraction was originally present in fractures and pores prior to drilling. They are typically much more saline than fracking fluids. While fracking fluids may contain 1,500 - 8,000 ppm of additives, produced brines have total dissolved solids from 30,000 to 150,000 ppm (McElreath, 2011). Produced waters contain natural organic compounds, salts, low levels of naturally occurring radioactive materials ( e.g. 238U, 232Th, 40K) and microorganisms ( USGS Factsheet FS 156-00). Inappropriate disposal of these fluids in the US has had negative environmental consequences (Adams, 2011).
5.29 Wastewater disposal - from shale gas production or CBM - requires storage, clean up and transportation, as well as safe and efficient disposal. Wastewater is ultimately a by-product of many industrial processes and treatment and disposal are heavily regulated in UK. This is discussed further in Chapter 7, with regards to unconventional oil & gas developments. Consequently, they are unlikely to present significant technical challenges, although they do represent costs to the operator.
5.30 After clean up, wastewater is typically released into rivers or pumped to sea. Underground injection is used in the US, but this process may be the cause of small earthquakes ( NRC, 2012).
5.31 When oil and/or gas wells come to the end of their productive life they are shut in, and then abandoned. Abandonment should be carried out such that wells do not represent a safety or environmental hazard, i.e. they should not leak hydrocarbons.
5.32 Concern has been expressed about the safety and environmental issues regarding abandoned wells and the UK (and all other countries) has regulations which operators must follow. The regulations also apply to shale gas and CBM wells. Since these are on land and often close to population centres, the issue of well abandonment has been raised in debates on shale gas development. Several hundred onshore UK wells have been successfully plugged, capped and abandoned, though in some cases the procedure may have been defective and some wells have leaked.
5.33 A recent review by Davies et al (2014) collated data on the integrity of (mostly) conventional oil and gas wells from around the world and made recommendations for future onshore UK unconventional oil and gas wells.
5.34 However, an important point to note is that conventional oil and gas wells are over-pressured prior to exploitation, and in some cases remain so after the end of economic production of hydrocarbons. In this case, if the well is left open, oil and/or gas will flow out due to the pressure being above hydrostatic.
5.35 In contrast, shale gas and CBM wells are by definition under-pressured and they do not naturally flow, unless the formation is massively fractured or the coal seam is dewatered - gas is then produced for a period until the pressure drops again (see Thorogood and Younger, 2014). Consequently, unconventional oil & gas wells should be much easier to deal with as long as the regulations are adhered to and monitoring is implemented.
5.36 There are a number of technical challenges associated with unconventional hydrocarbon extraction however, given the extensive experience of the oil and gas industry, none of these are seen as insurmountable.
5.37 Shale gas and CBM wells are under-pressured and methane does not flow naturally, which contrasts with the situation found in conventional gas wells. Therefore, it should be easier to deal with the abandonment of unconventional oil and gas wells, provided regulations are adhered to and monitoring is implemented.
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