OR/18/012 Specific vulnerability
|Loveless, S, Lewis, M A, Bloomfield, J P, Terrington, R, Stuart, M E, and Ward, R S. 2018. 3D groundwater vulnerability. British Geological Survey Internal Report, OR/18/012.|
Specific vulnerability accounts for both intrinsic vulnerability and factors that do not pertain to the intrinsic vulnerability of the receptor, but which would influence the risk to a potential receptor from a hydrocarbon activity — i.e. the hazards. Hazard factors include the extraction mechanism of the hydrocarbon (H1) and the local groundwater head gradient that might drive flow (H2). Rankings (numeric, representing a number of possible categories) and confidence levels (high, medium, low) are applied to each factor. A higher ranking implies a higher hazard. Both hazard factors are multiplied by the intrinsic vulnerability score to produce a specific vulnerability score.
The following section briefly describes the specific contamination pathways associated with conventional and unconventional hydrocarbon extraction techniques, providing the background to the H1 scores. More information on the history and characteristics of the techniques can be found in Appendix 5. Potential driving forces (H2) are then discussed and the methodologies for each hazard factor presented at the end of the respective sections.
Conventional oil and gas
In conventional oil and gas extraction, boreholes are drilled into a reservoir and oil and/or gas flows to the surface under natural pressure (BGS, 2011) (Figure 5.1). Conventional reservoir rocks are commonly sandstone or limestone with a relatively high porosity and permeability (from 1 mD to several D), allowing the oil and gas to flow. Hydrocarbons have a lower density than other crustal fluids and therefore migrate upwards through permeable rock and along discrete pathways. The hydrocarbons are prevented from further migration by low permeability traps such as a geological fault or low permeability rock unit behaving as a ‘cap rock’. This allows for the accumulation of hydrocarbons within the pore spaces of the reservoir. Where both oil and gas are present, gas overlies oil due to its lower density (Figure 5.1).
The main potential pathways for contamination arising from conventional oil and gas reservoirs is the borehole infrastructure and other existing/abandoned boreholes in the area (Figure 5.2). This is because conventional hydrocarbons can be exploited in areas with a large number of existing boreholes. Well integrity failure is also possible if reservoir stimulation techniques are used, such as hydraulic fracturing or enhanced oil recovery (EOR) (Ward et al., 2015). Additionally, pressure or permeability changes within the reservoir, perhaps due to stimulation techniques might also alter the behaviour of the fault or cap rock behaviour with respect to fluid movement and potentially allow leakage (Figure 5.2).
Since hydrocarbon reservoirs have relatively high porosity and permeability, the same rock unit could be an aquifer at shallower depths, and therefore, mass transfer is possible within the unit towards the aquifer where in continuity.
Shale gas and shale oil are extracted directly from organic rich shales (Figure 5.3). The low permeability of shales (<0.001 to 0.0001 mD) (CSUR, 2016) means that a proportion of gas or oil produced from the organic material in shales is trapped within the pore spaces. Gas can also be bound to the matrix by adsorption. Other tight (low permeability) reservoirs (such as limestones or siltstones) are also often called shale gas reservoirs even through the rocks do not contain a high enough proportion of clay minerals to generally be called shales (Lefebvre, 2017). The permeability of tight formations ranges from 0.001 to 0.1 mD (Naik, 2003). Similarly to shales, tight formations have small pore throat apertures (0.5–10 µm) and low delivery rates (Aguilera & Harding, 2008) and porosity of less than 10% (DECC, 2013a).
Shale gas is extracted via a borehole, which may be deviated from vertical and/or have horizontal sections within the shale (Gallegos and Varela, 2015). High volume hydraulic fracturing (fracking) is used to increase the permeability of the shale, allowing gas to flow from the shale to the borehole. The process involves injecting a high volume of ‘frack fluid’ (water containing a proppant and chemical additives) into the borehole under a very high pressure in order to fracture the rock surrounding the well. These induced fractures increase the shale porosity from 1–10% to 35% (Brownlow et al., 2016). The fractures are kept open by the proppant (sand or ceramic beads) after the borehole is depressurised to allow the gas to the surface. The chemical additives are used to optimise the efficiency of the hydraulic fracturing process (The Royal Society, 2012). Hydraulic fracturing is not always required for oil production from tight formations (US EPA, 2016). There are a number of potential pathways for contamination from shale gas exploitation. There is no requirement for a cap rock because the gas is trapped in the rock unit. Therefore, once gas is released, transport of gas and fluid through the rock mass is possible (Figure 5.4). There are no characteristic proximities between shales (or tight formations) and aquifers. In the US, 90% of disclosed wells had vertical separation distances between 880 m and nearly 4 km (US EPA, 2016) although the US Well File Review found that 20% of wells had <600 m vertical separation between the shallowest point of fractures and the base of aquifers (protected groundwater resources based on well authorisation documents and aquifer maps) (US EPA, 2015). In New Albany the vertical separation ranges from 30 to 490 m between source and aquifer, and from ~3 km to 4 km between aquifers and the Haynesville-Bossier shales (US EPA, 2016). In the UK a minimum depth of high volume hydraulic fracturing was set at 1 km in the UK Infrastructure Act (2015), which means that there is a minimum 600 m vertical separation between the ‘default’ maximum depth of designated groundwater bodies as indicated by UKTAG (2011) and shale gas hydrocarbon source unit formations.
Shales and tight formations are not commonly aquifers due to their low permeability (Aguilera & Harding, 2008). However, water-bearing zones can be present within shales or tight formations where depositional settings led to localised or transitional silt/sandstone or limestone deposition. For example, in Pavillion, Wyoming, the Wind River Formation is the principal source of groundwater and also one of the main gas hydrocarbon source units. Contamination of the groundwater here is thought to have occurred because stimulation fluids were directly injected into water-bearing units, but there was also casing failure at five production wells which probably allowed migration into water-bearing units (DiGiulio and Jackson, 2016).
Because of the high density of boreholes in areas where shale gas is being exploited in comparison to conventional hydrocarbons, there are more likely to be existing boreholes in the vicinity of new boreholes. The presence of horizontal boreholes increases the likelihood of the path of the new borehole being close to existing boreholes.
Ingraffea et al. (2014) found a six-fold higher incidence of cement and/or casing issues for shale gas wells relative to conventional wells from analysis of 75 505 compliance reports from Pennsylvania, 2000–2012. Borehole integrity failures may be more common when boreholes are used for high volume hydraulic fracturing due to the different geometries (longer and sometimes curved) and high volumes and pressures involved in the hydraulic fracturing process (e.g. Jackson et al., 2014). It is also difficult to maintain casings centred in the horizontal section of boreholes, which makes it difficult to ensure a good cementation of the casing (Lefebvre et al., 2017). Integrity failure may also occur due to ground movement and seismic events that could be triggered by hydraulic fracturing (Ward et al., 2015).
In a study of 68 drinking water wells above the Marcellus and Utica shales in Pennsylvania and upstate New York, Osborn et al. (2011) found an increase in the concentration of methane with proximity to shale gas boreholes when the boreholes were located within 1 km. Jackson et al., (2013b) also found a significant increase in methane and ethane concentrations in groundwater <1 km from shale gas boreholes in Pennsylvania, from 141 samples (including 60 from Osborn et al. (2011). They found no elevated methane in wells located more than 4 km from a borehole and propane and ethane were generally absent in wells located at distances of more than 1 km. Llewellyn et al. (2015) document a case in Pennsylvania where contamination in a number of wells is likely to have been caused by high volume frack fluids escaping from a shale borehole into an aquifer due to high pressures. Heilweil et al. (2015) found fugitive gas in a groundwater fed stream close to a Marcellus shale well under investigation for stray-gas. Fontenot et al. (2013) found that a number of chemicals exceeded the EPA’s Maximum Contaminant Limit in some wells within 3 km of active natural gas wells, from 100 tested drinking water wells overlying the Barnett Shale, Texas. Lower levels were detected outside of the Barnett Shale region and >3 km from active natural gas wells. The random distribution could, however, point to a number of causes, including the mobilisation of naturally occurring constituents, lowering of the water table or faulty drilling equipment and well casings.
Darrah et al. (2014) identified seven discrete clusters of fugitive gas contamination from shale gas wells, from 113 groundwater samples from the Marcellus Shale and one cluster from 20 samples from the Barnett Shale. They identified the cause of four of the clusters was due to failure of annulus cement, three faulty production casing and one to an underground gas well failure.
It should be noted that there are also numerous studies where high concentrations of methane in drinking water have been attributed to natural processes rather than wells (e.g. Molofsky et al., 2013; Christian et al., 2016; Wen et al., 2016; Harkness et al., 2017; Nicot et al., 2017a; Nicot et al., 2017b; Nicot et al., 2017c; Ward et al., 2017) and may be expected in areas where gas exists in the subsurface, or no significant increases of thermogenic methane were identified (e.g. Warner et al., 2013; McMahon, et al. 2015). This may reflect the time taken for contaminant migration, or different geological conditions or well completion characteristics. In addition to the size and nature of datasets analysed (Li et al., 2016). In parts of northern England legacy deep coal mines occur above shale gas resources. These may, in some places, be an additional contamination source and pathway (Monaghan, 2017).
Natural gas can be bound within coal seams by adsorption in which gas molecules adhere to the surfaces within the coal. This gas can be extracted in situ, i.e. directly from coal seams (Figure 5.5).
For the extraction of CBM a borehole is drilled into the coal seam and water is pumped out in order to lower the pressure in the seam (Jones et al., 2004). In some cases, particularly where there has previously been mining, coal-bearing strata may already be dewatered (Al-Jubori et al., 2009). The lowering of pressure allows methane to desorb from the internal surfaces of the coal and diffuse into cleats (fractures within the coal) where it is able to flow, either as free gas or dissolved in water, towards the production well (DECC, 2013b). A good permeability is necessary to allow flow of gas to the production well during CBM production. Bituminous coals can have permeabilities of 1 mD, sometimes up to 30 mD although this is often anisotropic (Jones et al., 2004). Permeability can be imparted by cleats, and in some cases this may be as high as 100 mD, for example in the San Juan basin in the U.S., where natural production rates are similar to conventional reservoirs (Al-Jubori, 2009). While the permeability of coal seams in the UK is likely to be low (Jones et al., 2004) and decrease with depth (Moore, 2012), cleats are common (due to their age) and can increase coal seam permeability (EA, 2014). In areas of pre-existing mines, the permeability of coal seams and surrounding strata is increased due to rock collapses associated with longwall mining; this can be up to 160–200 m above and 40–70 m below the worked seam (Jones et al., 2004).
Coal mine methane (CMM) and abandoned mine methane (AMM) can be considered as subdivisions of CBM. CMM involves the removal of methane from a working mine to enable safe mining, by capturing it at high concentrations. In the UK, ‘post drainage’ is favoured in which methane is captured from strata above and below worked seams via suction pumps (EA, 2014). For deep, gassy longwall mines, boreholes are drilled at an angle above and sometimes below worked seams (EA, 2014). Boreholes may also enter the seams from inside the mines (Karacan et al., 2011). AMM recovers gas that accumulates in abandoned mines which would otherwise find its way to the surface. Boreholes are drilled into underground roadways or former workings. Drilling may be used to link adjoining mines and improve connectivity and to aid minewater drainage away from production zones (EA, 2014). In AMM, gas is also released via suction pumps (EA, 2014). Coal seams in the UK are often interspersed with secondary aquifers. In the US, formation fluids in coal measures are often within the salinity threshold for some definitions of drinking water (US EPA, 2016). Coal Measures are also located in proximity to freshwater aquifers (Al-Jubori et al., 2009) in England, as they are often directly overlain by Permo-Triassic principal aquifers (Jones et al., 2004). Therefore, contaminants do not have to travel far from coal activities to reach a receptor. In addition, because CBM can take place at only 200 m bgl, this could be shallower than a receptor.
Many hydrocarbon source units for CBM in the UK are close to coal seams that have previously been worked and may have a high density of mines and abandoned boreholes (Figure 5.6). They are also generally highly fractured and faulted.
Hydraulic fractures are not necessary for CBM, although in England, despite coal beds being relatively well fractured due to a long history of tectonic deformation, permeability is relatively low. Hydraulic fractures for CBM are generally not created through high volume hydraulic fracturing and therefore are expected to be smaller in extent. In addition, because the hydrocarbon source unit is often shallower than 600 m bgl, they are more likely to be horizontal fractures than vertical.
De-gassing of coal seams could result in matrix shrinkage and formation of cleats (Moore, 2012) and associated depressurisation within the sub-surface has resulted in instability/subsidence outside England in relation to CBM (EA, 2014).
UCG is the process in which oxygen and steam or water are injected into a coal seam via a borehole resulting in the partial in-situ combustion of coal to produce a combustible gas mixture consisting of carbon dioxide, methane, hydrogen and carbon monoxide. The product gas is then extracted via a producing well (Jones et al., 2004). UCG relies on high permeability within the coal in order to allow links between the boreholes but coals in England are typically low permeability (Jones et al. 2004) (Figure 5.7).
As noted above for CBM, Coal Measures in England are often interspersed with secondary aquifers. In the US, formation fluids are often within the salinity threshold for some definitions of drinking water (US EPA, 2016). Coal Measures are also located in proximity to freshwater aquifers (Al-Jubori et al., 2009) in England and are often directly overlain by Permo-Triassic principal aquifers (Jones et al., 2004). Therefore, contaminants would be closer to a potential receptor. In addition, because UCG can take place at only 200 m bgl this might be shallower than a receptor.
Many possible hydrocarbon source units for UCG in England are close to coal seams that have previously been worked and may have a high density of mines and abandoned boreholes (Figure 5.8). Because of the age of the Coal Measures in the UK, they are also generally highly fractured and faulted due to their deformational history. It has been suggested that UCG should take place >45 m from faults (Shafirovich and Varma, 2009) since faults might provide pathways for contamination.
Because a cavity is generally created with UCG, ground instabilities and subsidence are common (Burton et al., 2006). This causes increased fracturing around the cavity and could cause borehole deformation (Figure 5.8) (Burton et al., 2006; Bhutto et al., 2013; Shafirovich and Varma, 2009).
Contaminant transport may be enhanced due to convection from increased temperatures and pressures (Burton et al., 2006). However, groundwater monitoring took place at Chinchilla, Australia, and did not reveal any contamination (Jones et al., 2004).
EXTRACTION MECHANISM OF HYDROCARBON (H1)
This hazard factor results directly from the proposed hydrocarbon source and activity; conventional oil and gas, shale gas, UCG and CBM; and the specific techniques that will be employed. It identifies the possible release mechanism of contaminants associated with particular hydrocarbon activities resulting from the expected changes to the subsurface, e.g. increasing the permeability due to the creation of new flow paths or convection of contaminants due to increased pressure and temperature. There are five possible hazard rankings (Table 5.1). However, this are indicative, and a variety of other stimulation mechanisms (e.g. radial jetting or maintenance of reservoir pressure by injection of fluid into the oil or gas-bearing formation) can also occur.
Sources of information
Whilst the presence of potential pathways and the characteristics of rocks between the source and receptor may contribute to the vulnerability of a receptor, a mechanism of transport is required for contamination to actually occur, i.e. to present a risk. Contaminant transport mechanisms include diffusion and advection. Diffusion is likely to be slow and not very significant with the distances and concentrations of chemicals involved in these processes compared to advection, which can transmit a greater volume of contaminants. Advection requires a driving force to make groundwater flow (e.g. Flewelling and Sharma, 2014).
In the majority of cases, the receptor will overlie the source and an upwards driving force will be required for contamination. Flewelling and Sharma (2014) and Birdsell et al. (2015) suggest that, generally, vertical hydraulic gradients are small and densities of deep fluids are high, preventing upwards migration. Contamination from methane and other light gases is more likely than from heavier ones due to their buoyancy. In England, groundwater flow paths tend to be controlled by topographic flow; from recharge areas in uplands (with high hydraulic head) to discharge areas in lowlands (with low hydraulic heads) (Downing et al., 1987). On a regional scale, this means that there is likely to be a downwards gradient at the margins or sides of a basin, and below OD (Ordnance Datum) there is likely to be an upwards head gradient in the centre of a basin. Other factors to consider include fluid buoyancy, palaeoflow systems and compacting sediments as discussed in Bethke (1989). There is little evidence of natural overpressurisation reported in England (e.g. DECC, 2013a). However, over-pressurised gas was encountered in the Hatfield Moors Gas Field in 1981 (Thorogood and Younger, 2015). Fluids are also known to flow from depth to the surface in some places, such as the hot springs at Bath and Buxton. High hydraulic heads seen at about 1,100 m bgl in the Sellafield area have recently been explained by relict heads from a wet-based ice sheet over the area (Black and Barker, 2016). Often the rate of upwards groundwater movement may be very low, taking in the order of thousands of years in deep basins to reach the surface, making it difficult to identify such flows (e.g. Llewellyn, 2014; Vengosh et al., 2014).
Some of the hydrocarbon activities listed above change subsurface pressures and provide an external driving force. During hydraulic fracturing, reservoir pressures are typically increased to about 15 MPa above virgin reservoir pressure, increasing hydraulic head by 1500 m (Brownlow et al., 2016). This pressure increase can drive fluids away from the stimulated zone into the surrounding rock and possibly through preferential flow pathways. However, during production, flow-back occurs and hydraulic heads are relaxed slightly (Brownlow et al., 2016). The time over which high heads are sustained is not well known. Lefebvre et al. (2017) and others suggest that it is unlikely that overpressures will be maintained after the production of a shale gas reservoir has finished. Brownlow et al. (2016) suggest that the increased heads of 1500 m during hydraulic fracturing decreased to nominal head values after 1 year, and decreased by a further 200 m after 15 years, inducing flow towards the well, consistent with other simulations and observations in the Eagle Ford shale, Texas. It should be noted that head propagation occurs over shorter timescales and greater distances than fluid migration (Brownlow et al., 2016).
The dewatering process associated with CBM lowers the water table and can create a zone of depressurisation around the borehole. This can mobilise gas and other contaminants from the source rock; however, generally the pathways will be towards, rather than away from, the borehole.
With UCG, convection of fluids surrounding the coal seam can be induced due to the high temperatures and pressures. This can force contaminants away from the source and towards a receptor.
HEAD GRADIENT DRIVING FLOW (H2)
This hazard factor identifies natural groundwater head gradients which would act as a driving force for fluid flow and/or contamination from the hydrocarbon source towards the receptors.
The key factors are the direction and rate of groundwater flow (velocity). A natural groundwater flow direction from the hydrocarbon source towards the receptor increases the specific vulnerability of the potential receptor. Where groundwater flow is from the receptor formation towards the hydrocarbon source this decreases the vulnerability of the potential receptor. There are two possible parameter ratings (Table 5.2).
For most AOIs, there is likely to be very limited data from which a head gradient, or even direction, can be inferred at depth. There is more information available for head gradients at shallower (<200 m) depths which can indicate groundwater flow directions in shallower units. If there is sufficient information it might be possible to infer the depth to which this applies.
At some sites, local hydraulic gradients have been measured, for example at Harwell, Oxfordshire, to 350 m depth (Alexander et al., 1987) and Sellafield, Cumbria, to 2000 m depth (Black and Barker, 2016). Downing et al. (1987) present conceptual models of large-scale, regional groundwater flow, with some identification or supposition of upwards/downwards flow for; the Eastern Province, Hampshire Province, Severn Province, Northwest Province.
Regional head gradients in the centre of basins at depth, where hydrocarbon sources are commonly found, are often in the upwards direction. Therefore, in accordance with the precautionary principle (e.g. EA, 2013) and unless there is contrary evidence, the head gradient is assumed to be from the hydrocarbon source to the receptor (i.e. the worst case scenario).
Sources of information
Drilling logs might contain useful information on hydraulic head including unexpected changes in pressure such as over-pressure or loss of fluid. Where such information exists, they can be used for locations within their immediate vicinity.
Head gradients can be inferred from hydrogeological evidence such as the presence of thermal springs, for example from the Carboniferous Limestone Supergroup at Bath and Hotwells (Bristol), Buxton and Matlock.
Conceptual models of groundwater head gradients and groundwater for England are presented by Downing et al. (1987) with some supporting data.
Environment Agency groundwater models.
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