**3. Results and discussion**

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

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

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

**Figure 4.** A regional map showing a subsection of the Karoo Supergroup with blue patterns indicating sills while

dolerite, their yields and the composition of the water are still a matter of debate.

/day) [21]. These values were obtained from pump

matrix transmissivities (between 0.5-50 m2

220 Effective and Sustainable Hydraulic Fracturing

green to red represents dykes in the area [2; 23].

that upward injection and production fluids would be limited.

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 indicated some interesting trends [27]. The report summarises both sampling from vertical and horizontal drilled wells and reports a full range of chemical and flow data. In addition to this report it was also required to evaluate the hydraulic fracturing fluid composition used in the stimulation of the shale gas well. Since it is uncertain what specific set of chemicals will be used in the hydraulic fracturing event, it was deemed the best possible solution to assess the generalised composition of these fluids. In regard to hydraulic fracturing process it should be kept in mind that although it is referred to as a single process it consists of multiple steps. Each step has a purpose in the hydraulic fracturing event as well as the transport of the propanant down the hole.

By means of an illustrative example it is possible to get a rough estimate of the extent of chemical usage in hydraulic fracturing. It has been stated that a vertical hydraulic fracturing

a generic summary which stated the percentage composition of hydraulic fracturing fluid as reported by the Department of Energy [32]. If these values are taken as a lower limit then the following deductions can be made from Figure 5. Water and sand component of the hydraulic

**Figure 5.** Generalised volume of hydraulic fracturing component used in well stimulation. Vertical well and horizontal

Additives employed in the vertical or horizontal fracturing is present in scales approaching tonnes. Chemicals that are of special concern in large quantities are the acid phase, petroleum distillate and isopropanol. The acid phase is composed of hydrochloric acid (10-15%) and is usually part of the first phase of fluids to be injected into the well. The main aim of the acid phase is for cleaning the perforations and initiating fissures in the near-wellbore rock (acidetching). A secondary consequence is that the acid injected does interact with the host rock formation which can mobilise certain metals, but the mobilisation is dependent on acid concentration and exposure to host rock formation [33]. Petroleum distillates and isopropanol is listed chemicals of concern (carcinogens, SDWA regulated chemicals and hazardous air pollutants in the USA) and is still used in hydraulic fracturing activities [31; 28; 30]. Other

fracturing process constitutes 99.51% of the total volume used.

litres of fluid; in contrast a single horizontal hydraulic fracturing

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223

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

litres of fluid. A pamphlet recently released by Energy in Depth gave

process requires 1 x 106

process requires 10 x 106

well is indicated in blue and red bars, respectively.

#### **3.1. Hydraulic fracturing process**

Considering the chemicals used during the hydraulic fracturing process, recent publication of hydraulic fracturing fluid compositions has significantly increased the transparency in the use of these chemicals [28; 29]. However, when examining the reported values in the component information disclosure, some reports indicate that there is still some components that are not listed and are most likely proprietary [30]. In the current paper only a single hydraulic fracturing composition is considered, i.e. gel hydraulic fracturing fluid. A number of hydraulic fracturing fluid setups does exist which can either be based on water (slick water), gel, hybrid, foam or gas (air, inert or petroleum gas). The type of hydraulic fracturing fluid used is dependent on a number of factors and service company preference [28].

A recent investigation by the House of Representatives in the USA [31] found that a list of 750 chemical compounds were used from 2005 to 2009. A number of chemical compounds that have been reported, included 29 chemicals that are known or possible human carcinogens and are regulated under the Safe Drinking Water Act or listed as hazardous air pollutants under the Clean Air Act [31]. BTEX compounds–benzene, toluene, xylene, and ethylbenzene– appeared in 60 of the hydraulic fracturing products used between 2005 and 2009. The hydraulic fracturing companies injected 43.1 million litres of products containing at least one BTEX chemical over the five year period. In many instances, the oil and gas service companies were unable to provide the Committee with a complete chemical makeup of the hydraulic fracturing fluids used [31]. Between 2005 and 2009, the companies used 355 million litres of 279 products that contained at least one chemical or component that the manufacturers deemed proprietary or a trade secret [31]. The practice of using BTEX is currently being phased out due to known issues [31].

Interestingly, most of the chemical components of hydraulic fracturing fluids can be described as either LNAPLs and DNAPLs from a South African context. In addition regarding the interpretation of the Water Act of South Africa, an unwanted consequence may result from the process of hydraulic fracturing. Most notably the process increases the permeability and hydraulic conductivity of the zone that is fractured. This in part can constitute an aquifer at a substantial depth from surface, in this instance it would be regarded as a controlled activity with a host of requirements that needs to be addressed to satisify regulatory practice.

By means of an illustrative example it is possible to get a rough estimate of the extent of chemical usage in hydraulic fracturing. It has been stated that a vertical hydraulic fracturing process requires 1 x 106 litres of fluid; in contrast a single horizontal hydraulic fracturing process requires 10 x 106 litres of fluid. A pamphlet recently released by Energy in Depth gave a generic summary which stated the percentage composition of hydraulic fracturing fluid as reported by the Department of Energy [32]. If these values are taken as a lower limit then the following deductions can be made from Figure 5. Water and sand component of the hydraulic fracturing process constitutes 99.51% of the total volume used.

indicated some interesting trends [27]. The report summarises both sampling from vertical and horizontal drilled wells and reports a full range of chemical and flow data. In addition to this report it was also required to evaluate the hydraulic fracturing fluid composition used in the stimulation of the shale gas well. Since it is uncertain what specific set of chemicals will be used in the hydraulic fracturing event, it was deemed the best possible solution to assess the generalised composition of these fluids. In regard to hydraulic fracturing process it should be kept in mind that although it is referred to as a single process it consists of multiple steps. Each step has a purpose in the hydraulic fracturing event as well as the transport of the propanant

Considering the chemicals used during the hydraulic fracturing process, recent publication of hydraulic fracturing fluid compositions has significantly increased the transparency in the use of these chemicals [28; 29]. However, when examining the reported values in the component information disclosure, some reports indicate that there is still some components that are not listed and are most likely proprietary [30]. In the current paper only a single hydraulic fracturing composition is considered, i.e. gel hydraulic fracturing fluid. A number of hydraulic fracturing fluid setups does exist which can either be based on water (slick water), gel, hybrid, foam or gas (air, inert or petroleum gas). The type of hydraulic fracturing fluid used is

A recent investigation by the House of Representatives in the USA [31] found that a list of 750 chemical compounds were used from 2005 to 2009. A number of chemical compounds that have been reported, included 29 chemicals that are known or possible human carcinogens and are regulated under the Safe Drinking Water Act or listed as hazardous air pollutants under the Clean Air Act [31]. BTEX compounds–benzene, toluene, xylene, and ethylbenzene– appeared in 60 of the hydraulic fracturing products used between 2005 and 2009. The hydraulic fracturing companies injected 43.1 million litres of products containing at least one BTEX chemical over the five year period. In many instances, the oil and gas service companies were unable to provide the Committee with a complete chemical makeup of the hydraulic fracturing fluids used [31]. Between 2005 and 2009, the companies used 355 million litres of 279 products that contained at least one chemical or component that the manufacturers deemed proprietary or a trade secret [31]. The practice of using BTEX is currently being phased out due to known

Interestingly, most of the chemical components of hydraulic fracturing fluids can be described as either LNAPLs and DNAPLs from a South African context. In addition regarding the interpretation of the Water Act of South Africa, an unwanted consequence may result from the process of hydraulic fracturing. Most notably the process increases the permeability and hydraulic conductivity of the zone that is fractured. This in part can constitute an aquifer at a substantial depth from surface, in this instance it would be regarded as a controlled activity

with a host of requirements that needs to be addressed to satisify regulatory practice.

dependent on a number of factors and service company preference [28].

down the hole.

issues [31].

**3.1. Hydraulic fracturing process**

222 Effective and Sustainable Hydraulic Fracturing

**Figure 5.** Generalised volume of hydraulic fracturing component used in well stimulation. Vertical well and horizontal well is indicated in blue and red bars, respectively.

Additives employed in the vertical or horizontal fracturing is present in scales approaching tonnes. Chemicals that are of special concern in large quantities are the acid phase, petroleum distillate and isopropanol. The acid phase is composed of hydrochloric acid (10-15%) and is usually part of the first phase of fluids to be injected into the well. The main aim of the acid phase is for cleaning the perforations and initiating fissures in the near-wellbore rock (acidetching). A secondary consequence is that the acid injected does interact with the host rock formation which can mobilise certain metals, but the mobilisation is dependent on acid concentration and exposure to host rock formation [33]. Petroleum distillates and isopropanol is listed chemicals of concern (carcinogens, SDWA regulated chemicals and hazardous air pollutants in the USA) and is still used in hydraulic fracturing activities [31; 28; 30]. Other chemicals that are also classified as chemicals of concern are ethylene glycol, dimethyl formamide (DMF) and hydrochloric acid. If these components are added together more than 3410 and 34100 litres of chemicals of concern is injected into a well to develop a vertical or horizontal hydraulic fractured well, respectively. These values represent a single hydraulic fracturing event and the whole process is repeated if another section is hydraulically fractured in a well. It is important to note that it is assumed that the additives represent 0.49% of the total volume, but it can be as high as 5% in some instances, depending on field circumstances (geology, depth, anisotropic stress, water content and stability).

unclear from present data what the potential might be. Factors that could influence the production of water in shales is the current hydrogeological environment of the shale forma‐ tions, i.e. hydraulic head (pre-hydraulic fracturing), hydraulic conductivity (pre-hydraulic

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

In the remainder of this paper the focus will be on the horizontal well systems only and their associated produced volumes and chemical composition. The total dissolved solids for these selected flowback wells have also been included in Table 3. It should be kept in mind that the backflow water not only consists of hydraulic fracturing fluid but also of chemicals that were produced from the geological formation in which the hydraulic fracturing event took place, thus resulting in a mixture of hydraulic fracturing fluid and shale chemical constituents. The volume of water is also a representation of water injected and water present in the shale, which initially depends on the storativity of the shale and the porosity. Most notable of the tables presented here is that there is a number of missing data points, in either the flowback volumes or total dissolved solids concentration values. In some regard this reduces the usefulness of the data but it does give a good indication of expected volumes and salt loading over time.

**Hydraulic Fluid (HF) Cumulative Volume of Flowback Water (FW)**

Day 5 (l)

Day 14 (l)

Day 90 (l)

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225

%FW/HF

Day 1\* (l)

A Vertical 6,366,805 628,000 1,662,371 2,388,466 37.5 B Vertical 14,979,147 174,091 1,714,201 2,180,988 2,844,283 19.0 C Horizontal 23,248,077 525,930 1,534,545 2,542,366 10.9 D Horizontal 3,361,627 453,750 1,284,140 1,580,016 1,778,273 52.9 E Horizontal 8,505,821 1,360,931 3,232,212 3,912,677 4,082,794 48.0 F Horizontal 12,400,214 520,206 1,721,832 1,960,472 2,768,446 22.3 G Horizontal 19,701,865 193,806 1,191,292 1,982,731 2,969,406 15.1 H Vertical 5,729,107 634,041 2,602,463 3,383,568 5,045,462 88.1 K Horizontal 11,252,167 914,336 1,274,442 1,506,087 13.4 M Horizontal 15,770,745 2,610,412 2,851,437 3,135,707 19.9 N Vertical 1,818,020 386,657 438,646 483,798 562,020 30.9 O Horizontal 15,375,026 815,764 3,052,874 19.9 Q Vertical 3,750,987 209,068 568,698 809,245 21.6 S Vertical 2,616,931 332,919 1,245,189 1,485,736 1,704,821 65.1

fracturing), porosity and storativity.

Site Well Type

Total Volume (l)

**Table 2.** Reported hydraulic fracturing and flowback volumes from Hayes report [27].

At this stage the most significant threat that hydraulic fracturing fluid can pose is an uncon‐ trolled spill at surface [34]. This is due to the fact that once the hydraulic fracturing fluid has been injected into the subsurface, it reacts with the specified target components as well as the geological formation and subsurface water it comes into contact with. It is at this stage that the hydraulic fracturing fluid can undergo a number of chemical and physical processes to either precipitate, mobilise, react or undergo physical transformations (adsorption and absorption). In either instance the chemical component has been altered.

However, with current internal practices developed in the gas companies the likelihood of an uncontrolled spill have been significantly reduced. It is generally in the companies own best interest to minimise these events as it can affect future gas development rights and litigation. Spills that do occur on site is usually dealt with immediatly or a remediation plan is put into place [34].

#### **3.2. Backflow event after hydraulic fracturing**

The current section is focused on a report produced by Hayes [27] for the Marcellus Shale Coaliton. It is one of the few publically available documents that give an indepth report on injected and produced water in a hydraulic fractured well system. The report is used as an illustrative example and it is recognised that the water qualities associated with the Karoo Supergroup will most likely differ. It should be noted that although flowback water is used in this section, that there is no decernable difference between the classification of flowback water and produced water (Table 2). Instead it is an artificial deliniation depending on who has currently control of the site, i.e., hydraulic fracturing team or the production team. Addition‐ ally, this section will be used to illustrate the mass of salt produced from these well systems, which in turn would indicate treatment requirements and disposal volumes. It is assumed that the salt will be present as a dry material that would be disposed of in an environmentally approved manner. From a South African perspective, the most likely development of gas well fields will be multiple wells on a single pad. This is due to infrastructure requirements and safety considerations.

The average flowback percentage of vertical and horizontal hydraulic fracturing wells are 43.7% and 25.3%, respectively. In Table 2 the average hydraulic fracturing volume used for vertical and horizontal wells are 5.8 million litres and 13.7 million litres, respectively. This would indicate that more than 50-70% of the fluid injected has been absorbed by the formation. In either instance it does represent a potential source of produced water over time and it is unclear from present data what the potential might be. Factors that could influence the production of water in shales is the current hydrogeological environment of the shale forma‐ tions, i.e. hydraulic head (pre-hydraulic fracturing), hydraulic conductivity (pre-hydraulic fracturing), porosity and storativity.

chemicals that are also classified as chemicals of concern are ethylene glycol, dimethyl formamide (DMF) and hydrochloric acid. If these components are added together more than 3410 and 34100 litres of chemicals of concern is injected into a well to develop a vertical or horizontal hydraulic fractured well, respectively. These values represent a single hydraulic fracturing event and the whole process is repeated if another section is hydraulically fractured in a well. It is important to note that it is assumed that the additives represent 0.49% of the total volume, but it can be as high as 5% in some instances, depending on field circumstances

At this stage the most significant threat that hydraulic fracturing fluid can pose is an uncon‐ trolled spill at surface [34]. This is due to the fact that once the hydraulic fracturing fluid has been injected into the subsurface, it reacts with the specified target components as well as the geological formation and subsurface water it comes into contact with. It is at this stage that the hydraulic fracturing fluid can undergo a number of chemical and physical processes to either precipitate, mobilise, react or undergo physical transformations (adsorption and absorption).

However, with current internal practices developed in the gas companies the likelihood of an uncontrolled spill have been significantly reduced. It is generally in the companies own best interest to minimise these events as it can affect future gas development rights and litigation. Spills that do occur on site is usually dealt with immediatly or a remediation plan is put into

The current section is focused on a report produced by Hayes [27] for the Marcellus Shale Coaliton. It is one of the few publically available documents that give an indepth report on injected and produced water in a hydraulic fractured well system. The report is used as an illustrative example and it is recognised that the water qualities associated with the Karoo Supergroup will most likely differ. It should be noted that although flowback water is used in this section, that there is no decernable difference between the classification of flowback water and produced water (Table 2). Instead it is an artificial deliniation depending on who has currently control of the site, i.e., hydraulic fracturing team or the production team. Addition‐ ally, this section will be used to illustrate the mass of salt produced from these well systems, which in turn would indicate treatment requirements and disposal volumes. It is assumed that the salt will be present as a dry material that would be disposed of in an environmentally approved manner. From a South African perspective, the most likely development of gas well fields will be multiple wells on a single pad. This is due to infrastructure requirements and

The average flowback percentage of vertical and horizontal hydraulic fracturing wells are 43.7% and 25.3%, respectively. In Table 2 the average hydraulic fracturing volume used for vertical and horizontal wells are 5.8 million litres and 13.7 million litres, respectively. This would indicate that more than 50-70% of the fluid injected has been absorbed by the formation. In either instance it does represent a potential source of produced water over time and it is

(geology, depth, anisotropic stress, water content and stability).

224 Effective and Sustainable Hydraulic Fracturing

In either instance the chemical component has been altered.

**3.2. Backflow event after hydraulic fracturing**

place [34].

safety considerations.

In the remainder of this paper the focus will be on the horizontal well systems only and their associated produced volumes and chemical composition. The total dissolved solids for these selected flowback wells have also been included in Table 3. It should be kept in mind that the backflow water not only consists of hydraulic fracturing fluid but also of chemicals that were produced from the geological formation in which the hydraulic fracturing event took place, thus resulting in a mixture of hydraulic fracturing fluid and shale chemical constituents. The volume of water is also a representation of water injected and water present in the shale, which initially depends on the storativity of the shale and the porosity. Most notable of the tables presented here is that there is a number of missing data points, in either the flowback volumes or total dissolved solids concentration values. In some regard this reduces the usefulness of the data but it does give a good indication of expected volumes and salt loading over time.


**Table 2.** Reported hydraulic fracturing and flowback volumes from Hayes report [27].


**Table 3.** Concentration of Total Dissolved Solids from Selected Sites (mg/l).

The average chemical salt loading in the return water was in excess of a 95 000 mg/l (Figure 6). Considering these values an expected salt load produced from a single well would be in the range of 241 tons of material, which would require adequate disposal regulations since the waste would contain materials classified as harmful to the environment (Sr, Ba, Li, Cl and Br). A further consideration in processing the material would be the quantity of salts produced during a specified time period. Data reported by Hayes [27] were analysed to derive salt loads at reported day intervals at which chemical sample analysis were performed (Table 4). From the data presented the salt loading values vary considerably over production time and that no singular analysis can be used to determine when the most salt from the hydraulic fracturing well would be produced. This is due to different geologies as well as hydrogeological factors (porosity, permeability and water content of the formation). Secondly, salt loads vary from as little as 45 tonnes to 439 tonnes at 90 day, indicating that a significant quantity of salts is produced from each of the respective wells. The cumulative salts produced from these six wells are in the order of 1 920 tonnes which should be disposed of in an environmentally sound methodology.

1.E-03

TDS Ca Mg Na K Alk Cl SO4 Br Fe Li Ba Sr

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227

**Species in Solution**

(tons) (tons) (tons) (tons) (tons)

**Figure 6.** Box-and-Whisker diagram presenting the average distribution of sampled sites chemical components.

Site 0 1 5 14 90

C 17 13 75 186 287\* D 5 4 38 65 96 E 50 39 142 227 353\* F 6 32 171 209 349\* G 38 14 139 273 439\* K 9 17 31 32 45\*

**Table 4.** Cumulative salt loads in tons at a specific day for the respective sites. Values with \* indicate projected values.

**Cumulative salt load Day**

M 6 65

O 41 14 294

1.E-02

1.E-01

1.E+00

1.E+01

**Concentration (mg/**

 **l)**

1.E+02

1.E+03

1.E+04

1.E+05

1.E+06

In order to determine the 90 day values, a linear regression method was used to fit the data to a logaritmic function. Cumulative salt loading values were used since it was composed of both the flowback volume and total dissolved solids (TDS) value. It was assume in the calculations that the decrease in flow volume would continue to follow a logaritmic function, as would typically be expected from a production well. The salt loading (TDS) had a similar pattern and could be expcted to increase in the same methodology for the 90 day time period. If these values are not considered for the 90 day production then the 14 day production in salt loading is expected to be 1 350 tonnes at an average of 169 tonnes.

**Site Day 0\* Day 1 Day 5 Day 14 Day 90**

C 719 24,700 61,900 110,000 267,000

D 1,410 9,020 40,700 155,000

The average chemical salt loading in the return water was in excess of a 95 000 mg/l (Figure 6). Considering these values an expected salt load produced from a single well would be in the range of 241 tons of material, which would require adequate disposal regulations since the waste would contain materials classified as harmful to the environment (Sr, Ba, Li, Cl and Br). A further consideration in processing the material would be the quantity of salts produced during a specified time period. Data reported by Hayes [27] were analysed to derive salt loads at reported day intervals at which chemical sample analysis were performed (Table 4). From the data presented the salt loading values vary considerably over production time and that no singular analysis can be used to determine when the most salt from the hydraulic fracturing well would be produced. This is due to different geologies as well as hydrogeological factors (porosity, permeability and water content of the formation). Secondly, salt loads vary from as little as 45 tonnes to 439 tonnes at 90 day, indicating that a significant quantity of salts is produced from each of the respective wells. The cumulative salts produced from these six wells are in the order of 1 920 tonnes which should be disposed of in an environmentally sound

In order to determine the 90 day values, a linear regression method was used to fit the data to a logaritmic function. Cumulative salt loading values were used since it was composed of both the flowback volume and total dissolved solids (TDS) value. It was assume in the calculations that the decrease in flow volume would continue to follow a logaritmic function, as would typically be expected from a production well. The salt loading (TDS) had a similar pattern and could be expcted to increase in the same methodology for the 90 day time period. If these values are not considered for the 90 day production then the 14 day production in salt loading is

E 5,910 28,900 55,100 124,000

226 Effective and Sustainable Hydraulic Fracturing

F 462 61,200 116,000 157,000

G 1,920 74,600 125,000 169,000

K 804 18,600 39,400 3,010

M 371 228,000

O 2,670 17,400 125,000 186,000

**Table 3.** Concentration of Total Dissolved Solids from Selected Sites (mg/l).

expected to be 1 350 tonnes at an average of 169 tonnes.

methodology.

**Figure 6.** Box-and-Whisker diagram presenting the average distribution of sampled sites chemical components.


**Table 4.** Cumulative salt loads in tons at a specific day for the respective sites. Values with \* indicate projected values.

Since all of the data which is available from hydraulic fracturing events are based on the Marcellus shale areas in the USA a question arose to the effect as how the Karoo shales compare the Marcellus shale. In order to investigate this question, Whitehill samples were collected from the Geological Department at the University of the Free State and subjected to a leaching test in acid. The results obtained are reported in Table 5 under the heading of Karoo. To draw a comparison between the shales the average chemical analysis of produced water from the Hayes report [27] and average composition of shales [35] were included. Due to different analysis methodologies and production environments these values could not be directly compared, instead ratios of the major elements were used to determine if a possible correlation did exist (Table 6). In general a good correlation existed between the reported sample compo‐ sitions in the Hem and Karoo data, with all results of the ratios within the same order when compared to each other. In contrast the Hayes report differed notably in the Ba/Ca, Ba/Li and Ba/Mg ratios which could possibly indicate that the use of hydraulic fracturing additives might have changed the chemical character of the produced water or that a substantial difference exists in the geological formation. Interestingly the remainder of the ratios are within an order of each other, especially the Ba/Sr, Ba/Na and Sr/Na ratios. This could possibly indicate that similar chemical properties in the produced water can be expected from the Karoo type shales in which the hydraulic fracturing events will take place. However, it should be kept in mind that without hydraulic fracturing field data these values can only be assumed to indicate possible chemical species. This clearly indicates that a test site should be established to determine the quantity and quality of the backflow water over an extended time period.

A recent sampling event took place at the Soekor core holes. Currently, the data set is limited and contains both the Soekor core hole data and surrounding well water. Interestingly, one of the core holes produced natural gas that could be ignited. The data is presented in Figure 7 in association with the Hayes report [27] data. Soekor data points are indicated as triangles, with SA 1, 5 and 7 representing samples from Soekor core holes. Sample data SA1 amd SA5 has a similar water type than that observed for the Hayes data set, which would indicate a highly mineralised water type. The main difference in the produced water is that the Soekor core holes have a reduced total dissolved solids content of approximately 6500-7200 mg/l. The third Soekor core hole water data (SA7) clearly has a Na/K-HCO3 water type and a TDS of 440mg/l, indicating the presence of a surface aquifer interaction or a recharge mechanism that is introducing freshwater into the system. Furthermore, it is unsure at this stage if the anulus of the bore is still intact or if short-circuiting is taking place at the site. The data presented is

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229

only preliminary and further data sets is required to fully characterise these sites.

**Figure 7.** Expanded Durov diagram illustrating the different water types characterised from the Marcellus [27] and

The Soekor core bores have been abandoned for nearly 40 years and there is still evidence that relatively high salinity water is produced from these sites. The rate of water production is relatively low compared to the data presented by Hayes [27], but as the production rate of water decreases at the sites it is currently unclear if there is still a hydraulic pressure that could produce water at surface. In the instance of the Soekor sites it does seem likely that recharge is occuring and that unless these holes are adequately sealed, a continuous discharge of water

Soekor sites.

and gas might be possible.


1. Hem report USGS [35]; 2. Hayes report GTI [27]; 3. Karoo Sample leached in lab with HCl acid

**Table 5.** Reported composition of shale samples obtained from various sources.


1. Hem report USGS [35]; 2. Hayes report GTI [27]; 3. Karoo Sample leached in lab with HCl acid

**Table 6.** Ratios of chemical compositions from reported shale samples.

A recent sampling event took place at the Soekor core holes. Currently, the data set is limited and contains both the Soekor core hole data and surrounding well water. Interestingly, one of the core holes produced natural gas that could be ignited. The data is presented in Figure 7 in association with the Hayes report [27] data. Soekor data points are indicated as triangles, with SA 1, 5 and 7 representing samples from Soekor core holes. Sample data SA1 amd SA5 has a similar water type than that observed for the Hayes data set, which would indicate a highly mineralised water type. The main difference in the produced water is that the Soekor core holes have a reduced total dissolved solids content of approximately 6500-7200 mg/l. The third Soekor core hole water data (SA7) clearly has a Na/K-HCO3 water type and a TDS of 440mg/l, indicating the presence of a surface aquifer interaction or a recharge mechanism that is introducing freshwater into the system. Furthermore, it is unsure at this stage if the anulus of the bore is still intact or if short-circuiting is taking place at the site. The data presented is only preliminary and further data sets is required to fully characterise these sites.

Since all of the data which is available from hydraulic fracturing events are based on the Marcellus shale areas in the USA a question arose to the effect as how the Karoo shales compare the Marcellus shale. In order to investigate this question, Whitehill samples were collected from the Geological Department at the University of the Free State and subjected to a leaching test in acid. The results obtained are reported in Table 5 under the heading of Karoo. To draw a comparison between the shales the average chemical analysis of produced water from the Hayes report [27] and average composition of shales [35] were included. Due to different analysis methodologies and production environments these values could not be directly compared, instead ratios of the major elements were used to determine if a possible correlation did exist (Table 6). In general a good correlation existed between the reported sample compo‐ sitions in the Hem and Karoo data, with all results of the ratios within the same order when compared to each other. In contrast the Hayes report differed notably in the Ba/Ca, Ba/Li and Ba/Mg ratios which could possibly indicate that the use of hydraulic fracturing additives might have changed the chemical character of the produced water or that a substantial difference exists in the geological formation. Interestingly the remainder of the ratios are within an order of each other, especially the Ba/Sr, Ba/Na and Sr/Na ratios. This could possibly indicate that similar chemical properties in the produced water can be expected from the Karoo type shales in which the hydraulic fracturing events will take place. However, it should be kept in mind that without hydraulic fracturing field data these values can only be assumed to indicate possible chemical species. This clearly indicates that a test site should be established to determine the quantity and quality of the backflow water over an extended time period.

Ba Ca Fe Li Sr Mg K Na

Ba/Sr Ba/Ca Ba/Li Ba/Mg Ca/Mg Ba/Na Sr/Na

Hem1 0.86 0.01 5.43 0.02 1.37 0.05 0.06 Hayes2 0.94 0.18 22.17 2.13 11.61 0.06 0.07 Karoo3 0.84 0.01 2.70 0.01 7.79 0.05 0.06

Hem1 250 22500 38800 46 290 16400 24900 4850 Hayes2 1552 8451 64 70 1650 728 237 24043 Karoo3 2.7 2400 770 1 3.2 308 50 50

**Source Element (mg/l)**

228 Effective and Sustainable Hydraulic Fracturing

**Table 5.** Reported composition of shale samples obtained from various sources.

**Source Element (mg/l)**

**Table 6.** Ratios of chemical compositions from reported shale samples.

1. Hem report USGS [35]; 2. Hayes report GTI [27]; 3. Karoo Sample leached in lab with HCl acid

1. Hem report USGS [35]; 2. Hayes report GTI [27]; 3. Karoo Sample leached in lab with HCl acid

**Figure 7.** Expanded Durov diagram illustrating the different water types characterised from the Marcellus [27] and Soekor sites.

The Soekor core bores have been abandoned for nearly 40 years and there is still evidence that relatively high salinity water is produced from these sites. The rate of water production is relatively low compared to the data presented by Hayes [27], but as the production rate of water decreases at the sites it is currently unclear if there is still a hydraulic pressure that could produce water at surface. In the instance of the Soekor sites it does seem likely that recharge is occuring and that unless these holes are adequately sealed, a continuous discharge of water and gas might be possible.

#### **3.3. Environmental impacts of hydraulic fracturing**

The concerns over hydraulic fracturing centre on a few main issues (Figure 8): (1) migration of gas, (2) migration of fracturing fluids, (3) water use, (4) management of produced water, (5) surface spills and (6) identification of chemical additives. Each of these issues will be addressed in the following numbered sections, it is a summary of best practice guidelines to prevent uncontrolled releases of hydraulic fracturing fluid into the environment or to protect the environment within a reasonable limit of practice.

requirements. To date, only a few productive Utica/Collingwood Shale gas wells have been drilled in Michigan and the potential for more extensive development is unknown; however, the DEQ is taking a proactive approach in addressing large-scale hydraulic fracturing as well

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

**1. Migration of gas or fracture fluids.** A major concern in natural gas development is the prevention of migration of gas or other fluids out of the reservoir and into overlying strata, particularly fresh water aquifers. In cases where this has occurred, it has been the result of well construction problems and not of hydraulic fracturing itself [36; 37]. At depths of about 610 meters or less, fractures propagate horizontally due to the natural stress regime of the rock. This confines the fractures to the gas reservoir. At greater depths, fractures may propagate vertically; however, characteristics of overlying rock layers prevent fractures from extending above the top of the gas reservoir. The installation of steel pipe ("casing"), encased in cement, is key to preventing migration of gas or fluids. Michigan regulations require that each oil and gas well have a casing and cementing plan that will effectively contain gas and other fluids within the wellbore, whether related to fracturing or not. Surface casing must be set a minimum of 35 meters into the bedrock and 35 meters below any fresh water zones and cemented from the base of the casing to the ground surface. Before fracturing or other operations can take place to complete a well for production, an additional string of production casing must be set to the depth of the reservoir and cemented in place. Depending on depth, additional protective casing may be required. To provide additional protection for aquifers and well integrity, the DEQ imposes a permit condition for wells in shallow reservoirs prohibiting hydraulic fractur‐ ing within 15 meters of the base of the surface casing. In addition, Instruction 1-2011 requires reporting of volumes, rates, and pressures (including pressure immediately outside of the pipe used to inject the fracturing fluid). Also, DEQ staff check wells in the vicinity to assure there are no wells or other features that could serve as conduits for

**2. Water use.** A fracture treatment of a typical Antrim gas well requires about 189 m3

needed to fracture a horizontal well may be up to 18 927 m3

significant adverse impact to groundwater or surface water.

water. In the emerging Utica/Collingwood Shale gas development, the amount of water

during a growing season. Withdrawal of water for oil and gas operations is exempt from the requirements of Michigan's water withdrawal statute; however, Instruction 1-2011 requires the operator to perform the same water withdrawal impact assessment as any other user of large volumes of water. It also requires installation and monitoring of an observation well if there is a freshwater supply well within one-quarter mile. The DEQ will not approve a withdrawal of water for hydraulic fracturing if it is likely to cause a

**3. Management of produced water.** Proper management of produced water is essential in protecting public health and the environment. In Michigan, produced water must be managed. Hydraulic Fracturing and disposed of according to strict rules specifically applying to those fluids. The fluids must be contained in steel tanks and transported to

is the volume of water typically used by eight to ten acres of corn

of

or more. To put this in

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

231

as other issues associated with deep shale gas development.

unwanted movement of fracturing fluids.

perspective, 18 927 m3

**Figure 8.** Main concerns regarding impacts of hydraulic fracturing on the environment.

Michigan's laws and rules effectively protect water and other natural resources as well as public health and safety from potential adverse effects of hydraulic fracturing. The Department of Environmental Quality (DEQ) has more than 50 staff employed in enforcing these state requirements. To date, only a few productive Utica/Collingwood Shale gas wells have been drilled in Michigan and the potential for more extensive development is unknown; however, the DEQ is taking a proactive approach in addressing large-scale hydraulic fracturing as well as other issues associated with deep shale gas development.

**3.3. Environmental impacts of hydraulic fracturing**

230 Effective and Sustainable Hydraulic Fracturing

environment within a reasonable limit of practice.

**Figure 8.** Main concerns regarding impacts of hydraulic fracturing on the environment.

Michigan's laws and rules effectively protect water and other natural resources as well as public health and safety from potential adverse effects of hydraulic fracturing. The Department of Environmental Quality (DEQ) has more than 50 staff employed in enforcing these state

The concerns over hydraulic fracturing centre on a few main issues (Figure 8): (1) migration of gas, (2) migration of fracturing fluids, (3) water use, (4) management of produced water, (5) surface spills and (6) identification of chemical additives. Each of these issues will be addressed in the following numbered sections, it is a summary of best practice guidelines to prevent uncontrolled releases of hydraulic fracturing fluid into the environment or to protect the


disposal wells where they are injected into deep rock layers that are isolated from fresh water supplies. The disposal wells are licensed by both the DEQ and the U.S. Environ‐ mental Protection Agency, and must be tested periodically to assure well integrity. Instruction 1-2011 requires reporting of the volume of flowback water recovered after a hydraulic fracturing operation.

**•** In addition post-closure monitoring should be conducted to ensure that well failure does

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

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233

South Africa has in the past been heavily dependent on its rich coal resources to supply it of electricity and fuel; with the discovery of an unconventional terrestrial gas resource it is currently entering a new age of energy independence. The development of this resource has put a strain on local communities due to fears of contaminated surface water and groundwater resources. The area currently being investigated, has both a historical and national significance and emotions are running high. Due to the sensitivity of South Africans regarding the Karoo, a great deal of care is required when gas exploration and eventual development occurs in this area. Key concerns is that the environment will be impacted to such an extent that it will be irrevocably changed. The geology of the area is to a certain extent complex and has dolerite sills and dykes which intrude the country rock. However, the Ecca formations of the Karoo has a considerable carbon content and suitable thickness to make it an ideal target for shale gas development. In this paper the process of hydraulic fracturing have been investigated from a hydrochemical perspective. Firstly, the composition of hydraulic fracturing fluids and the possible risks it pose to the surface and subsurface systems. Secondly, backflow water was evaluated for the Marcellus Shale since no current hydraulic fracturing program has been initiated in South Africa to target the Ecca shale formations. A summary of the key parameters were discussed as well as the production of flowback water and salt loading. Issues relating to salt loading were mainly related to treatment plants and the ability to effectively dispose of the produced brines and salts. A limited set of samples were incorporated into this paper from the Soekor core holes, and similar trends in water type was observed for both the Soekor sites

Environmental impacts due to hydraulic fracturing activities were discussed. Due to South Africa's recent introduction to unconventional gas development a number of important regulatory processes does not exist, i.e. well and site inspectors. The state of Michigan's proactive approach to regulating shale gas development addressed most of the issues which will be prevelent in the South African regulators mind. Finally, key differences between the regulatory environments were presented as well as unique challenges that faces South Africa

We would like to acknowledge the University of the Free State and Water Research Commis‐ sion of South Africa for funding. Dr. L. Chevallier for the geological information and assistance

not cause upward migration of contaminants (i.e. Soekor sites).

**4. Conclusions**

and Marcellus samples.

**Acknowledgements**

in strata characterisation.

in developing the unconventional gas resource.


The regulations enforced in Michigan was designed for the state specifically, in the instance of South Africa the following key differences will need to be considered.


**•** In addition post-closure monitoring should be conducted to ensure that well failure does not cause upward migration of contaminants (i.e. Soekor sites).
