**2. Problem formulation**

It was found that only the lower Ecca Group shales [7] within the dry gas window south of latitude 29°S have comparable total organic carbon contents to those of producing shales elsewhere in the USA (Table 1). The upper Ecca Group shales, namely the Tierberg Formation [13], average only 1.2 percent organic carbon [14], which is significantly lower than the 3 to 12 percent range applicable to producing shales (Table 1). The Dwyka Group also contains black shales with between 0.1 and 4.3 percent total organic carbon, averaging 1.9 percent [15; 14]. However, these shales are thin and restricted, being interbedded with diamictite and sand‐ stone, with the thickest shales (50 to 60 m) occurring in only 3 out of 45 deep wells investigated. The lower Ecca Group comprises black, organic-rich shale of the Whitehill Formation [16] overlying dark grey shale of the Prince Albert Formation (Figure 3) [17]. The Whitehill Formation pinches out northeastwards along a line stretching from Hertzogville in the Free State to Coffee Bay in Eastern Cape Province [14]. Northeast of this line, the Whitehill Forma‐ tion correlates with the middle part of the sandstone-dominated Vryheid Formation and the Prince Albert Formation grades into shale of the Pietermaritzburg Formation (Figure 3). In the area between Coffee Bay and Harding, the Whitehill and Vryheid Formations are separated

The gas production probability was delineated by Rowsell and De Swardt [7] using the results of desorbed gas analysis on core samples from the deep Soekor wells. The gaseous hydrocar‐ bons (methane to pentane) are absorbed on to the fine-grained constituents of shales and can be desorbed by low-temperature acid hydrolysis [7]. Samples yielding high proportions of C1 gas (methane) and C2/C1 (Ethane/Methane) relative to C3/C1 (Propane/Methane) indicate a potential for dry gas. The trend of increasing maturity due to increasing depth of burial southwards across the basin is supported by the results from other parameters, namely vitrinite reflectance, CR/CT ratios, illite crystallinity and spore colour index. For dry gas generation, vitrinite reflectance values should be between 2 and 5 percent. In the main Karoo Basin south of latitude 29°S, values for shale of the Ecca and Dwyka Groups vary between 1.8 and 4.4 percent [7]. Branch et al. [19] measured vitrinite reflectance values between 3.5 and 5.3 percent for shale of the Whitehill Formation and between 4.0 and 6.4 percent for shale of the Prince Albert Formation in well SA1/66 in the southwestern part of the basin some 60 km north of the basin margin. These correspond to the dry gas and metamorphic maturation stages, which indicates that shales in the southern extremity of the present basin are over-mature and can no longer generate dry gas. CR/CT ratios (residual, non-volatile carbon after pyrolysis to total carbon in the kerogen or organic material) gives an indication of the ability of the shale to produce additional amounts of hydrocarbons if heated to sufficiently high temperatures with lower ratios corresponding to higher potential. The results more or less correspond to the findings of the desorbed gas analysis [7]. Illite crystallinity or Kübler index is a measure of the width in millimetres of the 10 Å diffraction peak at half its height. It gives an indication of the maturity level of the shale with decreasing indices corresponding to increasing maturity [7]. The results of Soekor's investigations indicate a trend of increasing Kübler index from south to north across the Karoo Basin in shales of the Ecca and Dwyka Groups. In the southern part of the basin, south of approximately 30°S, the average indices are less than 4 and correspond to the metagenesis stage and possible preservation of dry gas. Comparative data to the Marcellus Shale and Barnett Shale is presented in Table 1. The percentage organic carbon

by a continuous shale succession [18].

218 Effective and Sustainable Hydraulic Fracturing

The major concern to date in the Karoo is the contamination of readily accessible water supply, i.e. surface water or groundwater resources. The development of an unconventional gas field does not occur in a matter of months, with a typical initiation phase of 10 years before gas production can continuously take place [20; 3]. In the instance of South Africa, a number of issues restrict the development of an effective gas extraction project. The infrastructure for gas transport (pipelines) in South Africa is very limited since no conventional terrestrial gas fields exist within the borders of the country. The Soekor wells drilled between 1965 and 1977 have yielded only tentative clues to the availability of gas in the Karoo basin. In this regard the major gas companies have to do a comprehensive exploration and verification program that could last from 3-6 years depending on the geological complexity of the development area. This would be followed by a pilot study to evaluate the basic characteristics of the reservoir which can be done on a number of sites simultaniously over a period of 2-4 years. Finally, if the gas in place is adequate then the process can be developed into full production of gas which can last for 30-100 years depending on gas prices and availability within the shales.

The geology of South Africa is quite varied considering the land size. One distinguishing feature of the geology is the presence of dolerite sills and dykes (Figure 4). The stack of sedimentary strata above the targeted formation in the Karoo consists of a succession of shale, mudrock, sandstone and dolerite. Each of these rock-types are generally characterised by low matrix transmissivities (between 0.5-50 m2 /day) [21]. These values were obtained from pump tests carried out on Karoo aquifers less than 200 m deep. Matrix transmissivities at greater depth would therefore be expected to be even less than these values, however this still needs to be confirmed in the future. Dolerite matrix has also been found to be quite impermeable [22] but due to the process of intrussion it can also act as an conduit. It is expected that the process of well field development would take into consideration the presence of these structures and that upward injection and production fluids would be limited.

The key question is: Can dykes act as vertical conduits for groundwater flow or hydraulic fracturing fluids? From current literature available [2; 23], it is clear that many water strikes occur between 0-70 metres below ground level (i.e. in the weathered zone) and are found at the contact dyke-sediment. Below 70 metres the water strikes are found along transgressive fractures. The main mechanism of flow dynamics at depth and around dykes is associated with sub-horizontal fractures. These fractures are not linked to one another and collect water from the matrix (dual porosity medium). The influence of dolerite dykes on vertical ground‐ water circulation at depth seems therefore to be limited, but cannot be excluded due to limited data availability. The T-values from different case studies also show that permeability of the

Hydrochemical and Hydrogeological Impact of Hydraulic Fracturing in the Karoo, South Africa

http://dx.doi.org/10.5772/56310

221

However there is evidence of a natural connection between deep groundwater systems and the surface, as evidenced by sixteen naturally occurring warm water (thermal) springs

Currently within popular literature hydraulic fracturing and well field development is grouped together under the phrase of fracking. This is clearly incorrect as gas companies refer to fracking as the process of hydraulic fracturing of the formation (shale or gas containing strata) for the purpose of increasing the porosity and permeability of the system to extract shale gas. In order to effectively evaluate the risks associated with hydraulic fracturing, it is best to assess the whole process in which an unconventional shale gas well is developed. This will include the drilling, hydraulic fracturing, well completion, production phase and post closure

Due to the lack of current data on the Karoo (Permian), secondary sources are required to infer possible issues in this area. Firstly, to assist in the investigation international studies were required for a comparative basis to describe the influence of shale gas development programs. These areas included the Marcellus (Devonian, Pennsylvania), Antrim (Upper Devonian, Biogenic, Ohio) and Barnett (Mississippian, Texas) shale plays. These were selected due to their state of unconventional gas development and regulatory framework. One report that has recently been made available for public scrituny that contains some measurement data has

C) in the main Karoo Basin south of latitude 28 degrees [25; 26]. These waters originate at a maximum depth of between 450 m and 1 150 m, as calculated from the geothermal gradient and the surface temperature of the waters. All the waters are according to Kent [25] are originally meteoritic and mainly deviate in composition due to differences in different compositions of the different rock lithologies associated with the spring, indicating also the presence of connate water. The waters of the central and eastern Karoo have NaCl as the prominent constituent with total dissolved solids ranging from 480-780 mg/l. A few springs are, however characterised by high NaHCO3 and SO4 contents, e.g. Stinkfontein, south of Beaufort West and the spring at Cradock. Biogenic methane is one of the main gases commonly associated with the hot springs in the main Karoo Basin and in some instances constitutes the

dykes is too low to allow for major flow in the dykes themselves [24].

only gas present. The other gases present are mainly H2, N2, He and Ar [25].

(26-41o

of the well field itself.

**3. Results and discussion**

Many of the areas where the shale formations have the potential to represent a good prospec‐ tive target for exploration are also characterised by multiple dolerite intrusions. Drilling in a dolerite sill environment will face challenges that can be overcome if sufficient investigation is carried out on these intrusive structures at depth. There is sparse information on the structure of deep dolerite sills and associated deep groundwater and water strikes in the Karoo lithos‐ tratigraphic formations. All available data comes from groundwater exploration drilling at shallow to medium depth (< 300 m). Several groundwater strikes were intercepted at that depth [2]. Below this depth, the presence of deep water strikes in the Karoo formations and associated dolerite, their yields and the composition of the water are still a matter of debate.

**Figure 4.** A regional map showing a subsection of the Karoo Supergroup with blue patterns indicating sills while green to red represents dykes in the area [2; 23].

The key question is: Can dykes act as vertical conduits for groundwater flow or hydraulic fracturing fluids? From current literature available [2; 23], it is clear that many water strikes occur between 0-70 metres below ground level (i.e. in the weathered zone) and are found at the contact dyke-sediment. Below 70 metres the water strikes are found along transgressive fractures. The main mechanism of flow dynamics at depth and around dykes is associated with sub-horizontal fractures. These fractures are not linked to one another and collect water from the matrix (dual porosity medium). The influence of dolerite dykes on vertical ground‐ water circulation at depth seems therefore to be limited, but cannot be excluded due to limited data availability. The T-values from different case studies also show that permeability of the dykes is too low to allow for major flow in the dykes themselves [24].

However there is evidence of a natural connection between deep groundwater systems and the surface, as evidenced by sixteen naturally occurring warm water (thermal) springs (26-41o C) in the main Karoo Basin south of latitude 28 degrees [25; 26]. These waters originate at a maximum depth of between 450 m and 1 150 m, as calculated from the geothermal gradient and the surface temperature of the waters. All the waters are according to Kent [25] are originally meteoritic and mainly deviate in composition due to differences in different compositions of the different rock lithologies associated with the spring, indicating also the presence of connate water. The waters of the central and eastern Karoo have NaCl as the prominent constituent with total dissolved solids ranging from 480-780 mg/l. A few springs are, however characterised by high NaHCO3 and SO4 contents, e.g. Stinkfontein, south of Beaufort West and the spring at Cradock. Biogenic methane is one of the main gases commonly associated with the hot springs in the main Karoo Basin and in some instances constitutes the only gas present. The other gases present are mainly H2, N2, He and Ar [25].

Currently within popular literature hydraulic fracturing and well field development is grouped together under the phrase of fracking. This is clearly incorrect as gas companies refer to fracking as the process of hydraulic fracturing of the formation (shale or gas containing strata) for the purpose of increasing the porosity and permeability of the system to extract shale gas. In order to effectively evaluate the risks associated with hydraulic fracturing, it is best to assess the whole process in which an unconventional shale gas well is developed. This will include the drilling, hydraulic fracturing, well completion, production phase and post closure of the well field itself.
