Rocks in the intervening zone between the source and receptor can facilitate or hinder the transport of contaminants. The further apart the source and receptor are, and the increased time taken for contamination to travel from hydrocarbon source to receptor, the lower the likelihood of contamination reaching the receptor, (e.g. US EPA, 2016). Longer pathways may also allow longer exposure to microbial degradation and attenuation, and prevent contamination reaching the receptor. Certain properties of the rock mass (porosity, permeability, attenuation capacity) will make the transport of contaminants more or less likely. This pathway is identified as ‘R’ in Figure 5.4, Figure 5.6 and Figure 5.8.
The groundwater flow in sedimentary formations at depth is up to two orders of magnitude greater in the horizontal than in the vertical direction, and simulations have shown that the majority of flow following hydraulic fracturing is in the horizontal direction (Brownlow et al., 2016). This is due to the permeability anisotropy resulting from sedimentary layering. The movement of contaminants is controlled by the lowest permeability layer.
In the 3DGWV methodology, proximity is divided into two subfactors; vertical and lateral separation distances. It reflects the greater likelihood of contamination through the rock mass and preferential pathways when the hydrocarbon source unit and the potential receptor are closer. The spatial extent of permeability changes resulting from extraction processes, in particular, hydraulic fracturing are also considered (Section 4.1.1). Different separation distances have been used in other industries, such as mining (Section 4.6) and could be used to modify distances in different locations and for specific industries if this methodology is extended to other sub-surface activities.
There are more categories for the intrinsic vulnerability parameter range for the vertical than for the lateral separation because better estimates of vertical separation can be made using the 3DGWV LFV model, or borehole logs. Since groundwater flow at depth is generally greater in the
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horizontal direction than in the vertical direction the lateral separation has a greater weighting so that a given distance scores higher (or the same) for the lateral than vertical direction (
Table 4.1). There are also fewer categories for the lateral than vertical scores because of the lower resolution.
Table 4.1 Example separation distances (m) and total vertical and lateral scores Separation distance (m) Vertical score Lateral
score
4.1.1 Effect of hydraulic fractures
Induced hydraulic fractures are fractures thought to be micrometres (µm) in width (Younger, 2016), which are created to release gas from shale or other tight rock formations. Due to the orientation of stresses in the sub-surface, hydraulic fractures at depths > 1200 m are predominantly vertical and at depths < 600 m are predominantly horizontal, with a mixture of vertical and horizontal fractures in the interval between (Fisher and Warpinski, 2012).
Hydraulic fractures could potentially provide preferential pathways for contaminants from source to receptors depending on the height and aperture of the fractures and the vertical separation distance between the hydrocarbon source unit and the receptor. Even if the fractures do not directly link the source and receptor, they can shorten the pathway that a contaminant would have to travel without a preferential flow path (modified separation).
Local rock failure, which occurs as the hydraulic fractures form, creates microseismic events which can provide information on in-situ rock deformation. While geophysical data can be used to image fracture height in the subsurface (Fisher and Warpinski, 2012), data remains relatively limited since only 3% of hydraulic fracturing operations in North America are currently monitored with seismic arrays(Gassiat et al., 2013). Nevertheless, studies assessing induced fracture height from micro-seismic and micro-deformation data for high volume hydraulic fracturing indicate that most hydraulic fractures are less than 100 m in height (Davies et al., 2012; Fisher and Warpinski, 2012). Statistically, less than 1% of hydraulic fracturing stages have fractures that are greater than 350 m in height (Davies et al., 2012). On average, there are seven hydraulic fracturing stages per borehole, thus about one in fourteen boreholes could have a maximum fracture height exceeding 350 m. Monaghan (2014) used a similar cut-off of 305 m (1000 ft) for vertical separation between shale gas activities and coal mines in the Midland Valley based on communications with an experienced US shale gas company. The maximum upward propagation of recorded fractures in the data from five shale gas plays in the US, analysed by Davies et al. (2012), is 588 m in height.
This work also concluded that fracture height probabilities are likely to be over-estimated due to difficulties identifying smaller fractures. In addition, Fisher and Warpinski (2012) show that fracture height distributions differ between regions and shale formations and there is currently no information on possible hydraulic fracture heights for England. Hydraulic fractures from lower pressure/volume fluid injection are expected to be smaller in extent (e.g. Flewelling et al., 2013).
There is limited information on the lateral extent of hydraulic fractures. The US EPA (2016) report fractures extending to horizontal lengths of 300 m from borehole data in the Fisher and Warpinski
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(2012) dataset. Modelling of hydraulic fracturing in sandstone (at a depth of 640 m) indicates a potential fracture length of 244 m (Adachi et al., 2007). Evidence from well communications between closely spaced boreholes might also help to elucidate the fracture half lengths; Jackson et al. (2013a) report a borehole blow-out adjacent to a hydraulic fracturing borehole separated by a distance of 200 m. Interwellbore Communication (IWB) was also found to occur in the Barnett Shale Play in Texas at distances of 340 m and 760 m (US EPA, 2016). Lefebvre (2017) found that the average horizontal distance for well communication at depth was 400 m, with a range from 30 to 2000 m. From 179 wells in Oklahoma, Ajani and Kelkar (2012) (in US EPA, 2016) found that the maximum distance between wells in which an impact was identified was 2590 m (individual fracture length of ~ 1295 m). The likelihood of communication was < 10% for wells 1000 m apart (fracture length of 500 m) and up to 50% for wells < 300 m apart (fracture length 150 m).
Hydraulic fractures can also interact with other pathways such as faults or boreholes and seismicity resulting from hydraulic fracturing can impact borehole integrity as seen at Preece Hall, Lancashire (Ward et al., 2015).
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Vertical separation of hydrocarbon source unit and potential receptors
This is the shortest (perpendicular) distance between the top of the hydrocarbon source unit and the base of the overlying potential receptor or, where the potential receptor is below the hydrocarbon source unit, the perpendicular distance between the base of the hydrocarbon source rock unit and the top of the potential groundwater bodyreceptor.
There are eight possible vertical separation distance ratings (Table 4.2). The lowest rating is for > 1200 m, accounting for the maximum distance of natural hydraulic fracture height (Davies et al., 2012) and would be the minimum depth of hydraulic fracturing below groundwater in SPZ1. Other incorporated boundaries include 100 m (most likely height), 400 m (< 1 % of hydraulic fracturing stages have fractures > 350 m in height) and 600 m (maximum recorded height of induced hydraulic fracture). The weighting for this sub-factor is 1.5. If a receptor does not directly overlie the hydrocarbon activity footprint (but is within the area of interest) this should be given a rating of 1. The weighting for this subfactor is 1.5.
Table 4.2 Proximity of hydrocarbon source unit and potential receptor: Vertical separation.
Scores are preliminary.
Intrinsic vulnerability parameter range Rating (r)
Weighting (w)
>1200 m 1
1.5
900-1199 m 2
600-899 m 3
400-599 m 4
300-399 m 5
200-299 m 6
100-199 m 7
<99 m 8
Sources of information
Conceptual model (Section 2.2). Vertical separation is calculated from unit depths entered into the 3DGWV methodology spreadsheet.
Confidence
High to medium = conceptual model based on site specific information from nearby
boreholes. This will be dependent on the quality of the borehole log, proximity to the AOI and geological variability in the area.
Medium to low = conceptual model based on 3DGWV LithoFrame ViewerLFV 3D model, shale/ aquifer separation maps, cross-sections on geological maps and geological memoirs.
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