Hydraulic Fracturing in South Africa: The

potential long and short-term effects

Compton Colin Saunders

13718436

Thermal Energy Systems

26 SEPTEMBER 2014

ii

Table of Contents List of Figures ......................................................................................................................................... iii

List of Tables .......................................................................................................................................... iv

List of Abbreviation and Acronyms ....................................................................................................... v

1. Introduction ................................................................................................................................... 1

2. The South African Power Generation Arena ................................................................................ 2

2.1 Integrated Resource Plan ........................................................................................................ 2 2.2 Technology for generating electricity from gas as fuel........................................................... 3

2.2.1 Open cycle gas turbines (OCGT) ........................................................................................... 4

2.2.2 Combined cycle gas turbine (CCGT) ..................................................................................... 4

2.2.3 Gas Turbine Fuels ................................................................................................................. 5

2.3 Current South African Gas Generation Capacity........................................................................... 5

3. What Is Unconventional Natural Gas? .......................................................................................... 6

4. What Is Hydraulic Fracturing? ....................................................................................................... 7

5. South African Shale Gas Resource Estimate ................................................................................. 8

5.1 Resource assessment .................................................................................................................... 9 5.2 Prince Albert Shale ...................................................................................................................... 10 5.3 Whitehill Shale ............................................................................................................................ 10 5.4 Collingham Shale ......................................................................................................................... 10 5.5 Recent shale gas exploration activity .......................................................................................... 10

6. Environmental Impacts of Shale Gas Development ................................................................... 11

6.1 Supporting infrastructure and operations .................................................................................. 12 6.2 Management of hydraulic fracturing flowback and produced water ......................................... 12 6.3 Water consumption and supply .................................................................................................. 13 6.4 Contamination of gound water ................................................................................................... 13

6.4.1 The hydraulic fracturing water cycle ................................................................................... 14

6.4.2 Status quo............................................................................................................................ 15

6.6 Greenhouse gas emissions .......................................................................................................... 16 6.7 Earthquakes ................................................................................................................................ 18 6.8 Air pollution ................................................................................................................................ 20 6.9 Blowouts due to gas explosion ................................................................................................... 21

7. Benefits of Unconventional Gas .................................................................................................. 22

8. Conclusions .................................................................................................................................. 23

Bibliography.......................................................................................................................................... 26

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LIST OF FIGURES

Figure 1: New Build Technology Options for Big Gas and Moderate Decline Scenarios.

Source: (DOE 2013) ............................................................................................................................ 2

Figure 2: Global installed Gas Generation Capacity Projections (2005-2035). Source:

(Statistica 2014) .................................................................................................................................... 3

Figure 3: General Electric Gas Turbine. Source: (Boyce 2012a) ................................................. 4

Figure 4: Combined Cycle Gas Turbine Operation. Source: (Energy Australia 2014) .............. 4

Figure 5: Fuel Cost per Million BTUs. ............................................................................................... 5

Figure 6: Shale gas and other gas deposit geology. Source: (USGS 2002) .............................. 7

Figure 7: Basic Hydraulic Fracturing Process. Source: (Royal Society and Royal Academy of

Engineering 2012) ................................................................................................................................ 8

Figure 8: Demarcation of the Great Karoo and Little Karoo, South Africa. Source: (EIA 2013b)

................................................................................................................................................................ 8

Figure 9: Lower Ecca Group within Karoo Basin. Source: (EIA 2013b) ...................................... 9

Figure 10: Karoo Basin Technical Cooperation Permit Areas. Source: (EIA 2013b) .............. 11

Figure 11: Potential Hazards Associated With Hydraulic Fracturing. Source: (Howarth,

Ingraffea and Engelder 2011a) ........................................................................................................ 11

Figure 12: Water Cycle Stages of Hydraulic Fracturing. Source: (EPA 2014) ......................... 14

Figure 13: Emissions Reduction Trajectory. Source: (DEA 2014) ............................................. 17

Figure 14: Graphic illustration of mechanism which could induce earthquakes. On the (left) is

a representation of how increasing the poser pressure which is acting on a fault can induce

an earthquake. On the (right) is a representation of how an earthquake can be induced due to

altering the shear and normal stress acting on a fault. Source: (Ellsworth 2013) .................... 19

Figure 15: House that was damages by the Mw 5.7 earthquake in Oklahoma on 6 November

2011. Source: (Ellsworth, Robertson and Hook 2014) ................................................................. 19

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LIST OF TABLES

Table 1: The different unconventional gas types ..................................................................... 7

v

LIST OF ABBREVIATION AND ACRONYMS

DOE Department of Energy

(CH4) Methane

(CO2) carbon dioxide

APP Alternate Power Plan

bbl a barrel (unit)

CCGT Combined Cycle Gas Turbine

CSP Concentrated Solar Power

Dti Department of Trade and Industry

EEDSM Energy Efficiency Demand-side Management

EP Exploration Permit

EPA Environmental Protection Agency

GDP Gross Domestic Profit

GW Gigawatt

GWh Gigawatt hour

IPP Independent Power Producers

IRP Integrated Resource Plan

km kilometers

km2 Square kilometre

kWh Kilowatt hour

LCOE Levelised Cost Of Energy

m2 Square meter

MPRDA Mineral and Petroleum Resources Development Act

Mton Megaton

MW Megawatt

MWh Megawatt hour

OCGT Open Cycle Gas Turbine

Photovoltaic PV

REIPPPP Renewable Energy Independent Power Producer procurement programme

SAPVIA the South African Photovoltaic Industry Association

TCP Technical Cooperation Permit

TW Terawatt

TWh Terawatt hour

USA United States of America

WWF World Wide Fund for Nature South Africa

1. INTRODUCTION The world we live in has an insatiable and unabated appetite for energy. Although coal is still the main fuel source for power generation at 43 per cent in 2010 there has been a drive to explore more clean, safe, efficient and economic alternatives (EIA 2013a). Natural gas, which is currently globally the fastest growing fossil fuel, remains to be regarded as a more environmentally friendly fuel when it is compared to other available hydrocarbon fuels (EIA 2013a). During 2010 the global energy mix consisted of 22 per cent natural gas based power generation technology as it has become the fuel of choice for many for energy and industrial sectors across the globe (EIA 2013a). The increase in natural gas consumption for power generation is partly attributed to its reduced carbon intensity compared to conventional power generation fossil fuels such as oil or coal, making it an ideal fuel for countries that have emissions obligations and policies. Currently natural gas production is predominantly from conventional gas deposits found in rock such as sandstone which is porous however large unconventional gas deposits are found in impermeable geological formations such as shale. Once hale gas has been extracted it is the same as conventional natural gas (Finkel and Hays 2013). In the past it was too expensive and challenging from a technology perspective to extract gas from shale deposits, however this has changed with the introduction of unconventional drilling technology, horizontal drilling and high volume hydraulic fracturing (Finkel and Hays 2013). The method of producing gas via hydraulic fracturing is performed by injecting very large quantities of fracturing fluid, consisting of water, sand and other chemicals, deep underground into geological formations and opening cracks or fissures within shale formations. Countries such as The United States of America (USA) have largely implemented the unconventional drilling technology which has allowed them to become a net exporter of natural gas. Although there are proponents of the American gas revolution due to fracking who consider it an opportunity for the USA to become energy self-sufficient, there are detractors who are persisting that the development of unconventional gas production should be avoided. There is also another group who are lobbying for more investigation into the potential ecological and human health risks as well as better regulatory framework before additional investment is made into unconventional gas development. South Africa is currently experiencing the same points of controversial debate around hydraulic fracturing in the Karoo. A number of gas mining coming have planned to launch exploration campaigns within the Karoo in order to extract unconventional gas but they have been faced with determined opposition from various fraternities who are mostly concerned with the potential environmental effects. Initially the South African government placed restrictions on all exploration of shale gas deposits but the moratorium was lifted by the Minister of Minerals and Energy in 2012 with draft regulations around governing additional exploration and fracking soon following (Business Day 2012). This report will briefly explore the current energy arena in South Africa in order to understand how natural gas is positioned within the energy planning sector. Some attention is also given to gas fuelled power generation technology and its fuel types as an introduction to understanding technology selection in the event that natural gas becomes a major fuel energy source in South Africa. Unconventional gas is briefly explored in order to understand the different types of unconventional gas after which the production process, hydraulic fracturing, is explained followed by an overview of the South African shale gas resource potential. Extensive attention is then given to the potential negative impacts of unconventional gas development such as water contamination, air pollution and health impacts. A high level analysis is provided on the potential economic and social impacts, unconventional gas development will have on South Africa followed by concluding remarks.

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2. THE SOUTH AFRICAN POWER GENERATION ARENA South Africa is greatly still dependant on fossil fuels in order to run the country and its economy. There has been an emergent drive towards building energy generation assets of a more sustainable nature, as the country is faced with an energy crisis. Also South Africa, has responsibilities from a climate change perspective and needs to address high unemployment levels of 25 per cent (STATS SA 2013), in an economy which requires growth in order to uplift its people. The need for energy has always been linked to gross domestic profit (GDP) growth and although the Integrated Resource Plan (IRP) outlines long-term plans for developing electricity generation capacity it is still governed by aspects of the Electricity Regulations Act 4 of 2006 (South Africa 2011a) on new generation capacity. These conditions also stated the requirement to model scenarios proposed during planning; ensuring that in the aim to diversify the power generation mix, policy objectives are adhered to and that energy demand projections are considered (DOE 2009).

2.1 Integrated Resource Plan Promulgated in the Government Gazette No. 34263 (South Africa 2011a), the IRP 2010 for South Africa is regarded as a “living plan” that will be constantly reviewed as the energy, political and economic landscape of the country changes (DOE 2011). The Renewable Energy Independent Power Producer Programme (REIPPPP) has set into action goals set by objectives such as the generating 10 000 gigawatt-hours (GWh) from renewables (DME 2003b, DME 2003a). The IRP 2010 (DOE 2011) also included a Medium Term Risk Mitigation Plan determination envisaging new build natural gas capacity between 2019 and 2020 of 474 MW (DOE 2011). A 7.7 gigawatt (GW) base load determination is also included in the IRP 2010 and includes 2.6 GW of newly built power generation capacity between 2021 and 2025 for Liquefied Natural Gas (LNG) or Natural Gas utilising combined cycle gas turbines (CCGT) and open cycle gas turbines (OCGT) (DOE 2011). The IRP 2010 update released in 2013 considers a “Big Gas scenario” which looks at a scenario where there are major advances in development of local gas resources as well as neighbouring countries (DOE 2013). Figure 1 below shows that by 2030, 16330 MW CCGT and 4560 MW OCGT technology capacity will be required. This is extended to 62 480 MW CCGT and 6720 MW OCGT generation capacity by 2050 (DOE 2013).

Figure 1: New Build Technology Options for Big Gas and Moderate Decline Scenarios. Source: (DOE 2013)

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According to a report by Serfontein (2014) it is shown by the IRP 2010 that imported liquefied natural gas (LNG) is simply too costly and essentially limiting its potential use. Only in the event that large scale gas production development from hydraulic fracturing in the Karoo happened will South Africa experience a large update in the use of natural gas. Considerable exploration is still required in South Africa in order to understand the potential of shale gas development and based on the outcome of exploration the IRP 2010 update mentions three possible scenarios. The first case could be that it would simply be too costly to use shale gas for power generation and as a result energy generation technology based on natural gas will not constitute a large portion of the energy mix (Serfontein 2014, DOE 2013). The second case could be that even though shale gas offers an economical viable option for power generation the levelised cost of electricity compared to that of coal and nuclear is still very high. Natural gas will then most probably only be used to provide fuel for peaking power stations running gas turbines which would be more cost effective than using diesel as fuel. The cost of using natural gas as fuel for gas turbines would be around R0.34 per kwh compared to R3.00 per kwh (Ham 2012, Serfontein 2014, DOE 2013). The third case, known in the IRP 2010 update as the “Big Gas Scenario”, could be that there is abundant shale gas available locally and cost effective enough to use it to generate base load demand at less cost than coal or nuclear based plants. The potential for shale gas then to displace vast majority of nuclear, coal and renewable technologies is very likely (Serfontein 2014, DOE 2013). The timelines within the IRP will probably not be feasible in the event that the “Big Gas Scenario” comes to pass as it is not possible to compare the rest of the world with the USA who have drilled a quarter of a million holes over the past 10 years.

2.2 Technology for generating electricity from gas as fuel Two major gas based electricity generation technologies currently exist which is the Open Cycle Gas Turbine (OCGT) and the Combined Cycle Gas Turbine (CCGT). Often reference is made to CCGT and OCGT with the assumption that the reader is familiar the major differences between the technology and fuel types. This section will provide a brief overview of each gas based generation technology regarding its operation. Gas is a major source of electricity generation with around 1200 GW installed by 2010 and expected to grow to around 1300 GW by 2015 as seen in Figure 2.(Statistica 2014). This was around 22 per cent of the global power generation capacity in the year 2010 and the share is expected to grow to 24 per cent by 2040 (EIA 2013a).

Figure 2: Global installed Gas Generation Capacity Projections (2005-2035). Source: (Statistica 2014)

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2.2.1 Open cycle gas turbines (OCGT) OGCT power plants, commonly used for meeting peak-load demand, generally consists of a single compressor and gas turbine that is connected to electricity generator via a single shaft (ETSAP 2010). A gas turbine, as seen in Figure 3, sucks air into the engine intake where it is compressed and then ignited utilising fuel in the combustion chamber. The very hot exhaust gases which is produced during the process is then used to pass through the turbine which turns a shaft connected to the rotor. The rotor turns inside the stator of a generator and as a result produces electricity (Energy Australia 2014, ESKOM 2014). OGCTs have a moderate efficiency of around 45 per cent at full load (Boyce 2012a).

Figure 3: General Electric Gas Turbine. Source: (Boyce 2012a)

2.2.2 Combined cycle gas turbine (CCGT) CCGT power plants have the same base components as an OCGT plant but is the more dominant gas technology and used for intermediate as well as base load power. CCGT combines the gas turbine cycle with that of a steam turbine. The high temperature air leaving the as exhaust gas is captured by a “Heat Recovery Steam Generator” (HRSG) (Energy Australia 2014). The “Heat Recovery Steam Generator” makes use of the gas turbine exhaust gases to generate steam by boiling water. The created steam then feeds into a steam turbine which in addition to the gas turbine drives a second generator. Both the steam and gas turbine can then generate electricity (Energy Australia 2014). OCGT power plants generally have multiple gas turbines and due to technology improvements and the heat recovery steam generator are projected to have efficiencies in excess of 60 per cent by the year 2020 (ETSAP 2010, Boyce 2012a). CCGT power plants can respond quickly to power demand and even when operated at less than full load it can still achieve in excess of 50 per cent efficiency at 50 per cent loading (ETSAP 2010). Basic operation and components of a CCGT with a “Heat Recovery Steam Generator” can be seen below in Figure 4. Combined-cycle power plants take about 3 years to complete with construction taking about 18 months and permitting and engineering taking the rest of the time (Boyce 2012a). The investment cost of CCGT power plants is generally higher compared to OCGT (ESKOM 2014).

Figure 4: Combined Cycle Gas Turbine Operation. Source: (Energy Australia 2014)

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2.2.3 Gas Turbine Fuels

The inherent fuel flexibility gas turbines have is one of its great advantages and can utilise fuels across the spectrum from gases to solids. According to Boyce (2012b) natural gas, process gas, coal gas and vaporized fuel oil gas are amongst the traditional gaseous fuels used within gas turbines. Liquid fuels such as diesel, kerosene, heavy viscous residual fuels through to light volatile naphtha could be used as fuels within gas turbines. Natural gas is however the fuel of choice and generally used as the performance benchmark fuel on which turbine are compared (Boyce 2012b).

. Figure 5: Fuel Cost per Million BTUs.

The properties of gas turbine fuels do not really determine its cost and in certain cases better fuels can be bought for much less than a poor fuel. There are many factors which determine what constitutes as the most economical fuel for gas turbines but ideally the most economical fuel should be burnt even if it is not the least expensive (Boyce 2012b).

2.3 Current South African Gas Generation Capacity South Africa currently has four gas power stations which are Acacia 171 MW, Port Rex 171 MW, Ankerlig 1 338 MW and Gourikwa 746 MW. The Ankerlig Power Station in the Western Cape has nine open cycle gas turbines units that have a combined nominal capacity of 1 338 MW. The facility which currently runs on diesel trucked in from Cape Town suppliers, was designed in such a manner that would allow it to be converted to combined cycle gas turbines (CCGT) should natural gas become readily available in South Africa. According to ESKOM (2009) after the conversion to CCGT each of the units will produce and additional 80 MW, around 50 per cent more than its original capacity. This will boost the total nominal capacity to around 2070 MW. The Gourikwa Power Station in Mossel Bay has five open cycle gas turbines units that have a combined nominal capacity of 746 MW. The facility also currently runs on diesel and as the Ankerlig power station was designed in such a manner that would allow it to be converted to combined cycle gas turbines (CCGT) should natural gas become readily available in South Africa. There are investigations around opportunities to include natural gas as a fuel source which could be supplied by the adjacent PetroSA plant. According to ESKOM (2009) after the conversion to CCGTs each of the units will produce an additional 80 MW, around 50 per cent more than its original capacity. This will boost the total nominal capacity to around 1150 MW. Once the facilities have been converted to combined cycle gas turbines (CCGT) they would be operated to contribute to the mid-merit demand which is during from about 06:00 to 10:00

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over weekdays in addition to acting as peaking1 power stations (ESKOM 2009). According to PWC (2012) once this has been completed the facilities will improve its efficiency from around 32 per cent to 51 per cent and operate for 47 per cent of the year instead of the current 6 per cent. A report by Atomic Electricity (2011) notes that currently the diesel running cost of Ankerlig power station is in the region of R 3.00 per kWh which is seven times more than R 0.40 per kWh of other Eskom average electricity cost. During the current 6 per cent running time this facility uses 40-million litres of diesel per annum (Atomic Electricity 2011).

3. WHAT IS UNCONVENTIONAL NATURAL GAS? There are numerous economic as well as geological conditions which determines the definition of unconventional natural gas (Law and Curtis 2002, Perry and Lee 2007, The Centre for Global Energy Studies 2010). Generally natural gas is labelled to be unconventional if the permeability of the rock which the gas is located is smaller than 1 millidarcy2, this low permeability essentially makes it hard for the gas to flow. The resource deposits are also generally located over a large area and require well stimulation techniques with recovery only about 15 – 30 per cent (Pearson, Zeniewski and Gracceva 2012). The opposite is true for a deposit of natural gas, defined as conventional gas, trapped in rock material such as lime or sandstone where the permeability is in excess of 1000 microdarcy and allows gas to flow between its interconnected spaces and into well boreholes (The Centre for Global Energy Studies 2010). Vertical wells are generally sufficient to recover the gas and up to 80 per cent of the resource is recoverable (Pearson et al. 2012). Permeability, by itself, is not of much significance and selecting a singular value of permeability in order to define unconventional gas is not possible. According to Whitaker (1986) if the permeability of formations are within the microdarcy range it is possible to obtain commercial completion of reservoirs which are thick, under high pressure and very deep. The view held by Perry and Lee (2007) is that even though fractures are successfully treated in cases where reservoirs are thin, shallow and have low pressure permeabilities of several millidarcies could be required to establish gas flow rates which are economically viable. Economics also play a great role in defining what constitutes as unconventional gas. According to Perry and Lee (2007) and economic definition of unconventional gas is “natural gas that cannot be produced at economic flow rates nor in economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the reservoir to the wellbore”. This definition however could be reassessed as technology continues to advance. Literature indicates that that there are essentially four different types of gas which can be classified as unconventional gas. These four types are shale gas, coal-bed methane, tight gas and gas hydrates (Perry and Lee 2007, Ghosh and Prelas 2009, Pearson et al. 2012). In order to understand what shale gas is, Figure 6 and Table 1 provides a geological comparison of the four different unconventional gas types.

1 Peak times typically weekdays from 07:00 to 09:00 and 18:00 to 20:00.

2units of permeability

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Figure 6: Shale gas and other gas deposit geology. Source: (USGS 2002)

Table 1: The different unconventional gas types

Shale gas Shale gas is essentially natural gas deposits which are trapped in very fine-grained rock sediment which is known as shale and characterised by its ‘flaky’ appearance and qualities. This is commonly found in areas such as floodplains, river deltas or lake deposits. In the case of shale gas, shale has two functions as it can be the natural gas source, as well the reservoir. This can either be gas which is free that is captured in the shale rocks fissures and pores or gas which has been absorbed into the rock surface.

Coal-bed methane

Coal-bed methane is essentially natural gas which is captured within coal seams which is absorbed within the solid matrix of coal which has a very low permeability

Tight gas Tight gas is different from shale gas or coal-bed methane as it formed on the outside of the rock formations. Tight gas is natural gas which has migrated into and then trapped inside very impermeable, non-porous hard rock, sandstone or limestone formations. This process takes place over millions of years.

Methane hydrates

Methane hydrates also known as methane clathrate and often called “fiery ice” is a mixture of methane and water resulting in crystalline combination. The formation happens at low temperatures and under extreme pressure under the ocean as well as within the permafrost3.

Sources: (Ghosh and Prelas 2009, EIA 2012, Dickens and Quinby-Hunt 1994, Pearson et al. 2012)

4. WHAT IS HYDRAULIC FRACTURING? Hydraulic fracturing, also known as fracking, is primarily a technique used in gas or oil mining with the aim of increasing the well flow rate, as seen in Figure 7. The fracking process is started by constructing the required infrastructure, which includes the well. The depth which production well are drilled to are between 2.4 and 3 km (8000 – 10 000 feet) deep (Gidley and Engineers 1989, Donaldson, Alam and Begum 2013) and could have sections which are horizontal or directional. The process of creating a rock fracture is executed by pushing fracturing fluid down into the wellbore at a ratio which is enough to increase the pressure at the bottom of the wellbore to a pressure which is greater than that of the fracture or pressure gradient of the surrounding rock formations. The basic working fluid in the fracturing process consists of more than 90 per cent water and other chemicals, which are pushed into the rock or geological formations at extreme pressures during the hydraulic fracturing process (Broderick, Anderson, Wood, Gilbert, Sharmina, Footitt, Glynn and Nicholls 2011, Hazen and Sawyer 2009). Once the fractures have been created, an attempt is made by the operators to try and maintain the width of the fracture. This is done by introducing proppant, which is a solid

3 Permafrost is ground that stays at or below 0°C for at least two years.

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material that can be treated sand or other ceramic materials, into the fracturing fluid which prevents the closing of fractures after the injection of fracturing fluid is stopped and the fluid pressure is reduced. The fracture that has been treated with proppant is generally permeable to the extent where formation fluids can flow into the well. The introduction of oil, gas and geothermal energy required during the completing of the well and fracturing is known as formation fluids (U.S. DOE 2009). Once the fracturing process has been completed the pressure within the geologic formation will push the fluid introduced during fracturing back up to the surface where it can be captured and stored in containers or pits before it is disposed of or recycled. These fluids which were used during the process and then recovered are known as produced water. There are numerous options for the disposal of the produced water, or flowback as it is also called, such injecting it underground or simply releasing it into surface water (Gidley and Engineers 1989, Fjær, Holt, Horsrud, Raaen and Risnes 2008, Donaldson et al. 2013).

Figure 7: Basic Hydraulic Fracturing Process. Source: (Royal Society and Royal Academy of Engineering 2012)

5. SOUTH AFRICAN SHALE GAS RESOURCE ESTIMATE The Karoo basin which has existed for over 250 million years is a natural semi-desert area within South Africa. The region has not always been dry and was a wetlands and forest during geological history which provided very rich coal deposits. The Karoo area in South Africa is divided into two areas known as the Groot Karoo and the Little Karoo. The little Karoo is also known as the wet Karoo. The Swartberg Mountain Range running in parallel with the southern coastline from the east to the west creates the divide between the Great Karoo and the Little Karoo. There is a separation of the Karoo and the sea by the Outeniqua –Langeberg Mountain range which runs from the east to the west. The demarcation of the Great and Little Karoo can be seen in Figure 8. Large scale exploration has not been proposed within the Little Karoo but mainly confined to the southern parts of the Karoo basin.

Figure 8: Demarcation of the Great Karoo and Little Karoo, South Africa. Source: (EIA 2013b)

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The Karoo Basin, as seen in Figure 9, located in the in central and southern parts of South Africa is one 612273 km2 large sedimentary basin and holds dense, organic-rich shale, with good potential for shale gas within the southern regions (Catuneanu, Wopfner, Eriksson, Cairncross, Rubidge, Smith and Hancox 2005, EIA 2013b). There is however factors which could raise the risk of exploration as the shale gas resource quality can be affected by sill intrusions which could also reduce the use of seismic imaging.

Figure 9: Lower Ecca Group within Karoo Basin. Source: (EIA 2013b)

Priority has been given to the exploration of local gas and oil due to the fact that South Africa is net imported of gas mainly from Namibia and Mozambique. A Technical Cooperation Permit (TCP) is require to initiate exploration, this could then potentially lead to an Exploration Permit (EP) and ultimately a production contract which is very lucrative for gas development with company tax of 28 per cent and 7 per cent royalties (EIA 2013b). According to Petroleum Agency South Africa (2014), a Technical Cooperation Permit only allows the entity awarded a permit under section 77(1) of Mineral and Petroleum Resources Development Act (MPRDA) to perform a desktop study and obtain seismic data from other sources and does not allow activities related to prospecting or exploration. Technical Cooperation Permits (TCPs), for the pursuit of shale gas in the Karoo basin, have been signed with numerous large independent companies such as Royal Dutch Shell, the Falcon Oil & Gas/Chevron joint venture, the Sasol/Chesapeake/Statoil joint venture, Sunset Energy Ltd. of Australia and Anglo Coal of South Africa (EIA 2013b).

5.1 Resource assessment In 2011 there were reports which indicated that the southern Karoo basin had recoverable shale gas reserves in the region of 485 trillion cubic feet (TCF) (Kuuskraa, Stevens, Van Leeuwen and Moodhe 2011). However in a report by EIA (2013b) there was a 15 per cent reduction in prospective area for the three southern Karoo shale formations changing the area from 183371 km2 to 155865 km2. The South African shale gas resource potential then was reduced to 390 TCF opposed to 485 TCF found in 2011 reports (EIA 2013b). South Africa is currently ranked in the fifth position on potential technical recoverable unconventional gas reserves with its potential 390 TCF to 485 TCF (Kuuskraa et al. 2011) (EIA 2013b). The other top ranking countries are Russia (1680 TCF), Qatar (905 TCF), Saudi Arabia (252 TCF) and Nigeria (184 TCF) (Mkhabela and Laing 2012).

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A study was performed by Geel, Schulz, Booth, deWit and Horsfield (2013) to investigate the lower Ecca Group, noted by the red exploration area in Figure 10, of the Karoo super group about 200km northwest of Port Elizabeth. The Lower Ecca shales consist of the thick basal Prince Albert formation, which is overlaid by the thinner Collingham and Whitehill formations (EIA 2013b). Samples from the Prince Albert, Whitehill and Collingham formations were obtained by drilling to 300 meters below the surface after which numerous analytical techniques were utilised in order to try and determine which shales could be classified as potential sources of unconventional gas (Geel et al. 2013). The Prince Albert, Whitehill and Collingham formations were all assessed individually in terms of potential resources.

5.2 Prince Albert Shale The 155865 km2 Prince Albert prospective dry gas area has a Shale gas resource concentration in the region of 0.0166 TCF per km2. According to EIA (2013b) an estimated 385 TCF of risked shale gas is in-place based on restricted exploration data. Prince Albert Shale in the Karoo basin is estimated to have a technically recoverable shale gas resource of 77 TCF which is based on good total organic content (TOC) and reservoir mineralogy, balanced by intricate geology and volcanic intrusions within the potential area (EIA 2013b).

5.3 Whitehill Shale The 155865 km2 prospective dry gas area Whitehill Shale gas resource concentration in the region of 0.0229 TCF per km2. According to EIA (2013b) the Whitehill Shale resource is more defined compared to the Prince Albert Shale with an estimated 845 TCF of risked shale gas. Whitehill Shale in the Karoo basin is estimated to have a technically recoverable shale gas resource of 211 TCF which is based on good reservoir mineralogy but intricate geology (EIA 2013b).

5.4 Collingham Shale The 155865 km2 prospective dry gas area Collingham Shale gas resource concentration in the region of 0.01389 TCF per km2. According to EIA (2013b) the Collingham Shale resource has an estimated 328 TCF of risked shale gas. Collingham Shale in the Karoo basin is estimated to have a technically recoverable shale gas resource of 82 TCF (EIA 2013b). There is a large amount of uncertainly around assessing and characterising shale oil resources within South Africa. Shale exploration with the Karoo basin is in its infancy in South Africa and very few data exists especially for the Upper Ecca group of formations (EIA 2013b).

5.5 Recent shale gas exploration activity According to EIA (2013b) there has been a considerable amount of activity within the Shale gas exploration arena with Falcon Oil & Gas Ltd. obtaining a 30043 km2 technical cooperation permit (TCP) along the southern edge of the Karoo basin, they were also one of the first players within the prospective shale gas market in South Africa (EIA 2013b). However Shell has managed to secure larger technical cooperation permit of 184925 km2 with surrounds the Falcon Oil & Gas Ltd. area. A technical cooperation permit of 4610 km2 is held by Sunset Energy which is to the west of Falcon Oil & Gas Ltd. The joint venture by Sasol, Chesapeake and Statoil holds a technical cooperation permit of 88059 km2 while a technical cooperation permit of 49986 km2 is held by Anglo Coal which are north and east of Shell’s technical cooperation permit area respectively. In 2012 Chevron made an announcement that it would pursue shale gas resources in the Karoo by partnering with Falcon Oil & Gas Ltd. and starting

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seismic studies (Maylie and Flynn 2012). Figure 10 below indicated all the technical cooperation permit areas as previously mentioned.

Figure 10: Karoo Basin Technical Cooperation Permit Areas. Source: (EIA 2013b)

6. ENVIRONMENTAL IMPACTS OF SHALE GAS DEVELOPMENT Appropriate measures should be taken in order to protect human health and the environment during all types or resource extraction and utilisation such as unconventional gas development (Groat and Grimshaw 2012). The controversy around unconventional gas extraction and specifically hydraulic fracturing stems from concerns regarding the potential adverse or harmful impact all stages of the development process could have on the environment and human wellbeing. The following section will briefly address some of the issues associated with the unconventional gas development life cycle.

Figure 11: Potential Hazards Associated With Hydraulic Fracturing. Source: (Howarth, Ingraffea and Engelder 2011a)

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6.1 Supporting infrastructure and operations The quality of surface water might be affected by runoff, especially in the event of storms, during the time that wells are being constructed and supporting infrastructure such as gravel roads have not been improved (Groat and Grimshaw 2012). There is a need to protect the quality of surface water as well as avoid damage to the ecology around the site as there is a risk of soil erosion and the transference of sediment into streams. Attention should be given to the prevention of oil, grease and other pollutant spills and leaks during the period of construction as well as during operations. The development process of unconventional gas extensively affects the surrounding environment and ecological habitations. As an example with shale development in Marcellus having two thirds of its well pads constructed in a forest area resulting in 312.5 km2 of forest clearing and surrounding environmental damage (Groat and Grimshaw 2012). Considering the Karoo basin, Van Staden (2014) says that according to South African botanist and restoration ecologist in the Prince Albert area there will be numerous environmental and ecological impact associated with hydraulic fracturing in the Karoo. As vegetation needs to be stripped, there will be various sensitive plants and animals which are found in small distribution ranges that will become threatened (Van Staden 2014). Another alarming concern is that the hydraulic fracturing process essentially requires very large quantities of clean silica sand which is required to keep the fractures open. Clean silica sand would need to be sourced and essentially mined in close proximity to the hydraulic fracturing sites. The likelihood of an explosion of small silica sand mines will have a detrimental long-term impact of the ecology of Prince Albert. According to Van Staden (2014) the often unseen effects are much larger than anticipated. The removal of rock could leave small animals as well as plants without shading from the relentless Karoo sun and due to dust from fracking operations covering vegetation herbivores such as sheep, antelope and hares could experience significant tooth ware. All of these factors will leave permanent scars of the landscape of the Karoo (Van Staden 2014).

6.2 Management of hydraulic fracturing flowback and produced water Once the hydraulic fracturing had been achieved within the well and the pressure exerted by the fracturing fluid is relieved there is a percentage of the fluid which was injected which returns to the well bore and is called "flowback" water. This flowback water is returned to the surface where it is either recycled or treated and in many cases simply disposed of. The fluid returned as flowback consists of a mixture of flowback water as well as saline water coming from the geological formation which is called “produced" water. During the process of withdrawal there is an increase of the percentage of produced water as the flow increases which makes the flowback fluid more saline. The stage where produced water dominates the flow is a controversial topic (Groat and Grimshaw 2012). The percentage of fluid which returned as flowback spans a large range from 20 to 80 per cent, these numbers are not yet well understood, and can vastly differ for various shale areas. Flowback water consists of numerous substances such as silt, sand, clay, grease, oil, organic compounds and total dissolved solids from the shale formations. The shale gas development process is water intensive and it is important to have fracturing fluid return as recycling is increasingly promoted within operations. The more fluid is returned the less water will be required. The recycle and reuse of water is not purely just to minimise water consumption but also minimise the recycling which needs to be managed. According to Groat and Grimshaw (2012) one of the major controversy within the shale gas development

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process is how the combined flowback and produced water streams are managed from a recycling, treatment, uncontrolled release and simply discharging the fluid as wastewater. Flowback water has in the past mostly been disposed of by deep well injection. In addition to hydraulic fracturing fluid containing potentially harmful chemicals which could pollute water supplies. Flowback and produced water can also contain contaminants which occur naturally like arsenic.

6.3 Water consumption and supply The hydraulic fracturing process requires large quantities of water and could potentially deplete local water resources (Entrekin, Evans-White, Johnson and Hagenbuch 2011). Large volumes of water is required for drilling mud, extracting and treating of sand for proppant, the testing of gas pipelines for its transportation, gas processing facilities and other functions (Groat and Grimshaw 2012). The volumes of water that is required during the hydraulic fracturing process varies according to numerous factors such as the local formation geology, the depth and length of the gas well and the number of stages involved in the hydraulic fracturing process (Royal Society and Royal Academy of Engineering 2012). Understanding the overall water requirement is very important. According to Moore and Less (2012) the volume of water which is required during the hydraulically fractured operations of shale gas well, over a 10 year period is equal to the volume which will be required for water for a golf course for one month or operate a 1000 MW coal-fired power plant for half a day. Besides the amount of water that is required the rate at which water is extracted also needs to be considered. The hydraulic fracturing process is not continues as water is only required when drilling occurs and then during each of the fracturing stages. This offers shale gas development operators to consult with water suppliers regarding the status of their water resources and schedule operations when the water resource is not stressed (Moore and Less 2012). Attempts to quantify the implication of the water consumption during the unconventional gas development process have resulted in numerous metrics being used with the energy water intensity appearing to be the most popular. Although the unconventional gas development process requires large quantities of water there is a consensus amongst those researching the matter that compared to other forms of fuel, unconventional gas development water requirements are relatively small (Groat and Grimshaw 2012).

6.4 Contamination of gound water According to Osborn, Vengosh, Warner and Jackson (2011) the concerns regarding potential impact on groundwater is based on the discharge and fluid flow into aquifers as a result of the high pressure at which fracturing fluids are injected into gas wells; the potential discharge into the environment of toxins and radioactive materials of produced water as a result of deep saline formation water and fracturing fluids mixing; the explosive and asphyxiation hazard associated with natural gas; and the dependence of shallow ground water by rural communities and agriculture in the presence of gas well (Colborn, Kwiatkowski, Schultz and Bachran 2011, Osborn et al. 2011). There are many other environmental concerns associated with hydraulic fracturing but the potential risk to drinking water resources has been one of the major considerations. The EPA (2011c) embarked on developing a study plan which would clarify the relationship, in the event that any exists, between available drinking water resources and the process of hydraulic

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fracturing. The study was also designed to recognise the possible impacts hydraulic fracturing had on drinking water and understanding the factors which have the most influence in the severity and the frequency of any impacts that might arise (EPA 2011c). The study was also developed in order to offer decision-makers with answers to questions related to the five fundamental questions associated with the water lifecycle involved with hydraulic fracturing (EPA 2011c). The following section will briefly consider the hydraulic fracturing water cycle and touch on the related fundamental questions.

6.4.1 The hydraulic fracturing water cycle The water cycle, as seen in Figure 12, involved with the hydraulic fracturing process has 5 district stages. In the following section these stages will be briefly explained and expanded on in terms of possible water contamination risk.

Figure 12: Water Cycle Stages of Hydraulic Fracturing. Source: (EPA 2014)

First Stage: The acquisition of water In the first stage of the cycle very large amounts of water are drawn from surface as well as ground water resources. Ground water is normally found in aquifers underneath the surface of the earth while surface water is found in lakes, rivers, streams and so forth which are all open to the atmosphere (EPA 2014). Both ground and surface water is a major supply of fresh and drinkable water. This water is then used within the fracking process and can impact the drinking water resources by changing the quality of the available drinking water and therefor the amount of available drinking water (EPA 2011c, EPA 2014). According to the EPA (2014). there has been changes in strategy by some companies who recycle the wastewater generated by previous hydraulic fracturing projects instead of drawing new water from ground and surface resources. Second Stage: Chemical mixing Hydraulic fracturing fluid is created by combining the withdrawn water with proppant and other chemical additives. The chemical additives which are used are added for a host of various reasons. The potential impact on the drinking water resource is the accidental release of hydraulic fracturing fluid to fresh ground and surface water resource through onsite leaks or spills near well pads (EPA 2011c, EPA 2014).

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Third Stage: Well injection During the third stage hydraulic fluid is injected into the well at pressure, creating cracks in the geological formation that enables the release of gas into the well which is then collected at the surface. During this process there are a few scenarios which could potentially impact drinking water. Hydraulic fracturing fluid can be released into the ground water resources as a consequence of poorly constructed wells or poor operations. Hydraulic fracturing fluids could also move into aquifers carrying drinking water from target formations through natural or man-made features such as abandoned wells. There is also a risk that natural elements such as radioactive materials or metals which reside underground are mobilised to move into underground drinking water aquifers due to the activities associated with hydraulic fracturing (EPA 2011c, EPA 2014). Forth Stage: Flowback and produced water (Wastewaters due to hydraulic fracturing) Once the pressure within the well is released the hydraulic fracturing fluid, all the formation water as well as the released natural gas all begin to flow back up the well. All the fluids which come back up the well which also contain the hydraulic fracturing fluid chemical additives and other natural elements needs to be stored on the site and is typically done so in tanks or pits before it is treated, recycled or disposed of. There is a possibility that the stored combination of liquids can potentially spill or leak from the on-site storage and contaminate ground and surface water (EPA 2011c, EPA 2014). Fifth Stage: Treatment of wastewater and the disposal of waste There are a few methods by which waste water is handled. It can either be injected underground, treated or then disposed in surface water, or it is recycled by use in other hydraulic fracturing projects where it could be treated or simply reused. The inadequate treatment of wastewater which is returned to surface water resources could potentially contaminate drinking water. During the treating of drinking water the by-products formed in the process could react with contaminant disinfectants of hydraulic fracturing fluids which could affect the drinking water resources (EPA 2011c, EPA 2014).

6.4.2 Status quo The study conducted by EPA (2011c) resulted in the first scientifically linked underground water pollution to hydraulic fracturing activities. In a draft report released by the EPA (2011a) it was found that gas drilling activities were the cause of the contamination of local water resources in the town of Pavilion located in central Wyoming, USA. According to officials of the Environmental Protection Agency, the report indicates that at least 10 compounds related to fracking fluids were found as contaminates within the local water resources (EPA 2011a). According to Lustgarten and Kusnetz (2011) the finding of the report are contradictory to longstanding arguments by drilling companies regarding the environmental safety of the hydraulic fracturing process. Some of the arguments made by the drilling industry is that fluids would naturally be forced down and not up by hydrologic pressure; a watertight barrier is provided by deep geologic layers which prevents the upwards movement of chemicals; and that issues related to steel and concrete barriers around the gas well were not directly related to hydraulic fracturing (Lustgarten and Kusnetz 2011).

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The report has however been highly contested by EnCana, the gas company that owns the Pavillion gas wells, who deny that any of their actions were related to the contamination and blamed natural factors. The company further responded by noting the importance of hydrology and geology when considering sample results and that the gas fields in the area has gas-bearing zones in the near subsurface as well as general poor water quality (Lustgarten and Kusnetz 2011).

6.6 Greenhouse gas emissions The emissions by the hydraulic fracturing process have long been under scrutiny due to its potential contribution to greenhouse gasses. One of the main components of natural gas is methane (CH4) which in terms of a global warming perspective is 20 times more capable of trapping heat than carbon dioxide (CO2) (EPA 2010). Natural gas is regarded as a potential bridge fuel for the coming decades which has the potential of mitigating global warming compared to other conventional fuel but not much is really known what impact the mining of unconventional will have in terms of GHG emissions. A recent report states that, "Compared to coal, the footprint of shale gas is at least 20 per cent greater and perhaps more than twice as great on the 20-year horizon and is comparable when compared over 100 years." (Howarth, Santoro and Ingraffea 2011b:1). There are two main stages within the hydraulic fracturing process which are the injection and flowback stages. Fractures in the geological formations are made by injecting a slurry made of water, proppant and other chemicals into the well. The propped fractures which are kept open by the proppant then allows gas trapped in the geological formations to flow into the wells at an economically viable rate. Once the injection stage has been completed the flowback starts where over the course of a week or two some of the injected slurry is pushed back to the surface (Francis and Sergey 2012). The well also starts producing gas during the flowback stage and the quantity of the gas at this stage and how it is dealt with is pivotal to the debate on the GHG contribution during shale gas mining. The argument made is that during the flowback stage vast quantities of gas is released into the atmosphere which compared to conventional gas mining produces much more GHG emissions (Howarth et al. 2011a, Howarth et al. 2011b). There are even scenarios which on a lifetime basis compared to coal projects that shale gas has a higher GHG impact when certain assumptions are made around the global warming potential of gas (Howarth et al. 2011a, Howarth et al. 2011b). This view has also been expressed by various media sources such as The New York Times (Soraghan 2011) and The Irish Times (McDonald 2011). The conclusions by Howarth et al. (2011b) have however not gone unquestioned with Cathles, Brown, Taam and Hunter (2012) making the following comments regarding points which they found misleading. According to Cathles et al. (2012) there are two major aspects which needs to be assessed. The first consideration is the quantity of methane which actually is released into the environment during the unconventional gas production process. Howarth et al. (2011b) makes two major assumptions when estimating releases quantities: the first assumption being that instead of capturing or flaring of gas it is simply vented to the atmosphere during the drill out and pre-initial production steps, and secondly that during these stages the rate at which gas is discharged by the well is similar to the maximum or initial production rate. The criticism offered by Cathles et al. (2012) is that Howarth et al. (2011b) do not offer any documentation or evidence that this type or release rates and methods is industry practise; that their leakage assessment factor is seems to be about 10 times larger than most estimate; and that no consideration is given to future technology options to reduce emissions during this stage of the conventional and unconventional gas production process.

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The second major aspects questioned by Cathles et al. (2012) is the true effect that the escape of methane from gas production has on GHG and future climate change. It is argued that the comparison between gas and coal uses the most biased timeline or period, 20 years opposed to 100 years, and measurement basis of heat compared to electricity. In order to offer a more even comparison gas needs to replace coal as an electricity generating fuel as coal is mostly used for electricity generation. It is imperative to consider that methane has a much shorter lifetime than CO2 which has a long atmospheric lifetime when considering their respective impact. The global warming potential over 100 years for methane considers this but the 20 year Global Warming Potential does not (Cathles et al. 2012). Cathles et al. (2012) perform their own analysis which looks over a 100 year global warming potential period while focusing on power generation and using similar methods as that of Howarth et al. (2011b). Their conclusion is that gas production has 30–50 per cent less impact in terms of GHG effects compared to coal. Gas is regarded as the “cleaner” option as it offers other advantages as that it does not contain particulates such as ash, SO2 or NO2. This is significantly lower that the estimate derived by Howarth et al. (2011b) who conclude that gas potentially has double the greenhouse impact compared to coal. There are also many other views on the life-cycle GHG emissions as a result of unconventional gas production. Burnham, Han, Clark, Wang, Dunn and Palou-Rivera (2011) draws the conclusion that the GHG impact of unconventional gas production is marginally less compared to that of conventional gas production while Weber and Clavin (2012) conclude that the impact is similar. However Jiang, Griffin, Hendrickson, Jaramillo, VanBriesen and Venkatesh (2011) as well as Stephenson, Valle and Riera-Palou (2011) come to the conclusion that the GHG impact over the production life-cycle of unconventional gas production is marginally higher compared to that of conventional gas production. Howarth, Santoro and Ingraffea (2012) have defended their position and highlighted that the EPA adjusted their estimates on fugitive emissions by unconventional gas wells upwards in their 2011 inventory (EPA 2011b). The collusions made by Howarth et al. (2011b) is further supported by Hultman, Rebois, Scholten and Ramig (2011) in the case of the Barnett shale wells. Regardless of the varying views on the difference between and unconventional and conventional gas production there is a commonality in that all groups conclude that the GHG impact of generating power using shale gas or unconventional gas is much less compared to that of power which is generated using coal. South Africa produces 83 per cent of its total GHG emissions due to its use of coal to generate electricity which is a major environmental consideration (Kohler 2013).

Figure 13: Emissions Reduction Trajectory. Source: (DEA 2014)

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The President of South Africa, Jacob Zuma, made a commitment to take the required steps in order to reach emissions reduction goals of 34 per cent by the year 2020 and 42 per cent by the year 2025. This announcement was made in 2009 at the UNFCCC4 National Climate Summit as a result of the legal obligations South Africa has under the UNFCCC and its Kyoto Protocol (South Africa 2011b). The IRP 2010 (DOE 2013), see Figure 13, shows the required the “Plateau and Decline” trajectory required to meet the commitment made by the President. Careful consideration will need to be given regarding the exploitation of shale gas reserves within South Africa as the impact that gas mining might have on GHG emissions are still unsure and potentially detrimental to the environment and commitments in terms of emissions reductions.

6.7 Earthquakes Earthquakes induced by hydraulic fracturing is a real hazard which has received much attention although most events are small some larger seismic events have raised considerable public and professional concern. Apprehensions regarding seismic activity that is directly associated with hydraulic fracturing activities such as deep well fluid injection, small earthquake epicentres in close proximity to hydraulic fracturing wells and changes to the landscape have all been under the microscope (Meng and Ashby 2014, Ellsworth 2013). Industrial activity could potentially cause earthquakes. This has been a point of discussion in North America as well as Europe as earthquakes in uncommon locations have become more frequent. Earthquakes that are induced due to underground and surface mining, the extraction of gas and fluid from the ground and the injection of liquids into underground formations have long been identified as potential hazards. Hydraulic fracturing has however refocused attention on earthquakes which are induced by the process where production from tight shale formations is stimulated or by the injection of fluids into ground formations. A review was performed by Ellsworth (2013) where industrial activity is potentially linked to seismic activity; focus is given to the discarding of hydraulic fracturing wastewater by injection into subterranean wells; scientific interpretation of induced earthquakes is assessed; and the main scientific challenges around the hazard of induced earthquakes is assessed. Earthquakes potentially can occur within continental interiors irrespective of relatively low deformation rates (Petersen, Frankel, Harmsen, Mueller, Haller, Wheeler, Wesson, Zeng, Boyd, Perkins, Luco, Field, Wills and Rukstales 2008). According to Townend and Zoback (2000) this due to the shear pressure levels the interior of plates or near plate boundaries are often observed to be close to the strength limit of the crust. It is under such conditions that minor agitations could potentially and often do cause earthquakes (Nicholson and Wesson 1990, McGarr, Simpson and Seeber 2002, National Research Council 2013, Evans, Zappone, Kraft, Deichmann and Moia 2012). Figure 14 is a graphic illustration of how changes close to faults could potentially induce earthquakes. The extraction of unconventional gas from shale needs a network of open fractures linked to the borehole and requires horizontal drill holes which extend for quite a few kilometres in the shale formations. The process involves a few stages of hydraulic fracturing which would typically entail the pressurisations of small sections of the cased well in order to stimulate gas flow into the well. During each of these stages water is injected into the shale formations at high pressure and process deliberately prompts multiple micro earthquakes of which most are

4 United Nations Framework Convention on Climate Change

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have a moment magnitude5 of Mw < 1 (Ellsworth 2013). According to Ellsworth (2013) there have been numerous cases where fracking was the direct cause of earthquakes which could be felt but were too small to cause any structural damage. Even though these seismic events were too small to cause structural damage they are notable due to the generated public concern.

Figure 14: Graphic illustration of mechanism which could induce earthquakes. On the (left) is a representation of

how increasing the poser pressure which is acting on a fault can induce an earthquake. On the (right) is a representation of how an earthquake can be induced due to altering the shear and normal stress acting on a

fault. Source: (Ellsworth 2013)

South central Oklahoma experienced seismic events at a maximum of M6 2.9 which was discovered to have a time based correlation to fracking activities in the vicinity (Holland 2013). There are there cases such as in Blackpool, United Kingdom where fracking operations induced events that measured M 2.3 (Green and Styles 2012). A report by the BC Oil and Gas Commission (2012) identified hydraulic fracturing activities, specifically fluid injection close to pre-existing faults, to be the cause of 21 seismic events of which the largest was Mw 3.6 in the Horn River basin of British Columbia during 2009. On the 5th of November 2011, central Oklahoma was shaken by a Mw 5.0 earthquake which was followed by Mw 5.7 main shock just 20 hours later. There was a clear connection between injection wells and the earthquakes due to the initiating point of the earthquakes a mere 1.4 km from injection wells which were at the same depth as the earthquake hypocenters (Ellsworth 2013).

Figure 15: House that was damages by the Mw 5.7 earthquake in Oklahoma on 6 November 2011. Source:

(Ellsworth, Robertson and Hook 2014)

There are options for reducing the risk of earthquakes induced by hydraulic fracturing activities. One of the main challenges is reducing the related risk in operating environments where there is no access to abundant data. There is clearly some risk associated with and

5 The moment magnitude scale (MW) is an earthquake size unit of measurement related to the amount of energy that was released HANKS, T. C. & KANAMORI, H. 1979. A moment magnitude scale. Journal of Geophysical Research: Solid Earth, 84, 2348-2350.. 6 All other scales of earthquake measurement

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high-volumes and longer-term fluid injections into deep well (Frohlich 2012) irrespective whether most well are considered to be aseismic (National Research Council 2013, BC Oil and Gas Commission 2012). Earthquakes which are induced due to hydraulic fracturing of formations have lower risk, compared to fluid injection-induced earthquakes, as they tend to be much smaller in magnitude with some of the largest earthquakes induced by hydraulic fracturing have been well below the destruction limit for contemporary structure codes (Holland 2013, BC Oil and Gas Commission 2012). A potential way of managing some of the risk related to injection-induced earthquakes is to set thresholds around seismic activity in and around injection wells which can prompt a reduction in the rate of pressure or injection and in the event that there is an increase in the seismic activity there could be an increased curtailment of injection (Zoback 2012). In a few cases “traffic-light” systems have been implemented indicating seismic activity and assist providing an indication of whether operations should continue or be stopped. According to Ellsworth (2013) there is a need for industry to have clear requirements around operations with a firm scientific backing of regulation governing operations with a clear sense of assurance by the public that the set regulations are sufficient, being followed and being observed. According to Zoback (2012) there are 5 simple steps which could be followed in order to minimise the risk of triggering a seismic event when fluid is being injected into deep wells.

1. It is critical that the injection of fluids into active faults as well as into brittle rock is avoided.

2. The changes in pore pressures should be reduced by correctly selecting formations

and limiting the rate of fluid injection.

3. If there is a possibility that a seismic event could be triggered due to fluid injection, seismic monitoring arrays need to be installed locally.

4. There should pre-determined protocols on how operations will be altered in the event that a seismic event is triggered.

5. In the event that a seismicity is triggered and poses a potential hazard the operators need to be prepared to either leave the well or reduce the rate of injection.

6.8 Air pollution Natural gas, which mostly comprises of methane, contains a host of other chemicals such as benzene, alkanes and aromatic hydrocarbons (TREC 2009). Numerous ambient air studies have been performed in places such as Colorado, Texas, and Wyoming in the USA, which indicate that complex a combination of air pollutants of a direct as well as fugitive nature is emitted due to the unconventional natural gas development process. These pollutants is not only from the gas resource but also from sources of produced water, diesel engines and fracking fluids (Frazier 2009, CDPHE 2009, Walther 2011, Zielinska, Fujita and Campbell 2011). The potential contribution which is made by each of the unconventional natural gas development sources still needs to be determined and it is very likely that a number of the unconventional natural gas development sources if responsible for emission of petroleum hydrocarbons. The mixture of chemical pollutants can find its way to nearby situated residential areas or centres of human population (Walther 2011, GCPH 2010). A range of

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studies have been performed on the exposure of inhaling petroleum hydrocarbons within settings such as work environments and residential areas which are located in close proximity to refineries, petroleum facilities and oil contaminated areas. These studies all indicate that exposure increases the risk of experiencing acute myelogenous leukaemia, irritation of the eyes, acute childhood leukaemia, asthma related symptoms, headaches and multiple myeloma (Glass, Gray, Jolley, Gibbons, Sim, Fritschi, Adams, Bisby and Manuell 2003, Kirkeleit, Riise, Bratveit and Moen 2008, Brosselin, Rudant, Orsi, Leverger, Baruchel, Bertrand, Nelken, Robert, Michel, Margueritte, Perel, Mechinaud, Bordigoni, Hemon and Clavel 2009, Kim, Park, LeeAn, Ha, Kim, Kwon, Hong, Jeong, Hur, Cheong, Yi, Kim, Lee, Seo, Chang and Ha 2009, White, teWaterNaude, van der Walt, Ravenscroft, Roberts and Ehrlich 2009). A range of the petroleum hydrocarbons which are detected in these studies are all exist within and in the surrounding areas of an unconventional natural gas development (TREC 2009). There are certain substances, like benzene, toluene, and xylene, which already have an extensive knowledge base regarding information on exposure and toxicity. However there are other substances such as heptane, octane, and diethylbenzene which do not have such extensive knowledge base regarding the effects of exposure and its toxicity. A conclusions from studies performed in Garfield County Colorado, USA, where unconventional gas development is the only main industry besides agriculture, showed that the presence of benzene in the air elevated the risk of cancer, other disorders of the blood, immune system effects and other acute and chronic health issues (CDPHE 2007, CDPHE 2010, Coons and Walker 2008, ATSDR 2007a). The nervous system can also be severely negatively affected by inhaling alkanes, xylenes and benzene (Carpenter, Geary Jr, Myers, Nachreiner, Sullivan and King 1978, Nilsen, Haugen, Zahlsen, Halgunset, Helseth, Aarset and Eide 1988, Galvin and Marashi 1999, ATSDR 2007a, ATSDR 2007b). Numerous other limited studies were performed regarding the risk involved with air pollution related to unconventional gas development but none of the studies could identify risks related to the specific stages within the unconventional gas development process or risk of residents living close to gas wells compared to those living further from the gas wells. However the study performed by McKenzie, Witter, Newman and Adgate (2012) was able to identify specify risks to residents staying close to gas wells during the flowback stage of the gas well completion which was achieved by logging air quality data right at the border of the gas well when the flowback was happening.

6.9 Blowouts due to gas explosion

Gas explosion or blowouts, which is the uncontrolled ejection of gas from a well, can happen in the process of drilling a new well, during the time when fracking is taking place or when a water well is installed in an area where hydraulic fracturing was performed (Stag 2008). The general methods by which blowouts are prevented by the circulation of drilling muds or either by installing cement casing along the wellbore and then pumping fracturing fluids and as a last resort the implementation of Blow out preventers (Stag 2008). According to Stag (2008) the general occurrence of blowouts are when, due to formation irregularities, gas enters into the borehole as a result of coming across an unknown gas pocket or losing hydraulic fracturing fluids or drilling mud. During these events, also known as kick, there is a movement of gas up the wellbore and if it cannot be contained by the drilling mud or hydraulic fracturing fluids offering pressure or the well can be sufficiently sealed by the blowout preventer in the required time, a blowout will ensue which will allow gas as well as polluted produced waters to stream to the surface (Stag 2008).

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There have been numerous occurrences of blowouts such as those that happened in Colorado when natural gas as well as and produced water gushed out onto the surface over a 72 hour period. The blowout occurred as a landowner drilled for a new water well within the same area as which hydraulic fracturing was taking place, as his old well become contaminated due to hydraulic fracturing activities. Another case is that of EOG Resources who had a blowout in while in the process of performing hydraulic fracturing in Clearfield County, Pennsylvania, USA and had 132489 litres of fracturing fluids and natural gas flow out into the forest areas and surrounding environment (Stag 2008).

7. BENEFITS OF UNCONVENTIONAL GAS In order to understand the potential macro-economic benefits that unconventional gas production will have on the South African economy this section will explore two scenarios which were modelled in a report by Econometrix (2012). Although there is an estimated 390 TCF of recoverable shale case reserves (EIA 2013b) available the Econometrix (2012) report only considers two scenarios, Scenario 1 which assumed a potential resource size of 20 TCF and Scenario 2 which assumed a potential resource size of 50 TCF. The low assumption is based on reports by Petroleum Agency South Africa who only believe that 10 per cent of original assessments of 485 TCF are available (Econometrix 2012). The models considered by Econometrix (2012) uses a production lifespan of 25 years and is split into a five year ramp up, 15 year mature production period followed with a run out period of five years. Scenario 1 of the Econometrix (2012) report, which considers shale gas resource of 20 TCF, estimates that the turnover due to gas would be R1.17 trillion and modelled at R4.03 trillion in the case of upstream and downstream partakers when measured at 2010 prices. The total value estimated to be added to the economy is R2 trillion. During the matured production stage the employment numbers are estimated to reach around 355 000 jobs with R801 billion per year going towards the remuneration of employees. The South African government will receive in excess of R887 billion due to the gas projects (Econometrix 2012). The annual contribution, made by a 20 TCF gas resource, to the South African gross domestic product (GDP) will be 1.1 per cent in 2035 if an annual 4.5 per cent GDP growth rate is assumed. Scenario 2 of the Econometrix (2012) report, which considers shale gas resource of 50 TCF, estimates that the turnover due to gas would be R2.9 trillion and modelled at R9.5 trillion in the case of upstream and downstream partakers when measured at 2010 prices. The total value estimated to be added to the economy is R5 trillion. During the matured production stage the employment numbers are estimated to reach around 854 000 jobs with R1.937 trillion per year going towards the remuneration of employees. The South African government will receive in excess of R2.223 trillion due to the gas projects (Econometrix 2012). The annual contribution, made by a 50 TCF gas resource, to the South African gross domestic product (GDP) will be 2.8 per cent in 2035 if an annual 4.5 per cent GDP growth rate is assumed. According to Econometrix (2012) there are very few projects in the South African history books which would have had such large and sustained impact on the country’s economy. The macroeconomic aggregates are merely one example of how the economy could benefit while there are numerous other benefits which might not be as easy to measure. A large shale gas resource could potentially reduce poverty and provide employment across various sectors from large international energy corporations to small and micro enterprises. The general distribution of potential benefits, in terms of product availability upstream and downstream as well as the development of the economy within a part of the country which does not have much other prospects of growth of this size, offers an intriguing perspective. There exists and opportunity for the native region to export energy related products to other areas of the country as well as on a global scale provide offer value added services for exports (Econometrix 2012).

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8. CONCLUSIONS South African dependency on coal for most of its electricity generation could greatly be reduced by the discovery, extraction and use of shale gas. Natural gas has numerous other applications and can be used to provide industrial, commercial and domestic energy; as an automotive fuel; energy feedstock to produce fertilizer; converted to liquid fuels; and exported globally. There is still great uncertainty in the South African shale resource which essentially does not allow any definite long-term planning within the Integrated Resource Plan. However there are three scenarios modelled in the IRP 2010 update with the third scenario, “Big Gas Scenario”, being the most optimistic in terms of resource size and cost. This scenario could see a major shift in energy planning as coal, nuclear and renewable could be displaced by gas generation technology. This could potentially have devastating effects on the renewable energy sector which is currently experiencing major growth. As an alternate scenario shale gas could provide more cost effective fuel for peaking power stations which currently run on expensive diesel at R3.00 per kWh. (Atomic Electricity 2011). Some preparation is already being made to existing gas turbine power stations such as Ankerlig and Gourikwa power stations which have had environmental impact assessments performed in order to convert the existing open cycle gas turbines (OCGTs) to combined cycle gas turbines (CCGTs) which will increase their capacity from 1 338 MW to 2070 MW and 746 MW to 1150 MW respectively. Efficiency will also be increased from 32 per cent to above 50 per cent (ESKOM 2009). The environmental and health hazards associated with unconventional gas development is very controversial and there is a general theme where blame is shifted towards the petroleum and mining industry in general as it has seemed difficult to directly and exclusively associate hydraulic fracturing activities with negative environmental and health effects. The potential negative impacts due to hydraulic fracturing is present within all stages of the process starting at the supporting infrastructure and operations where potential pollution of surface water can be caused by runoff while supporting infrastructure is in the process of being constructed. The environment around the site during construction and operation are exposed to soil erosion, oil, grease, transference of sediment into streams, deforestation, destruction of sensitive habitats, dust pollution and celica sand mining activities (Groat and Grimshaw 2012, Van Staden 2014). The management of hydraulic fracturing flowback and produced water which can contain silt, sand, clay, grease, oil, organic compounds and natural contaminants like arsenic is another controversial topic as they are simply discarded as wastewater or exposed of by deep well injection. The hydraulic fracturing process requires large volumes of water and can threaten the availability of local water resources (Entrekin et al. 2011). Conventional gas wells only use up to 2 per cent of the water required by hydraulic fracturing (Howarth et al. 2011a). The exact volume of water required by hydraulic fracturing is determined by numerous factors such and formation geology and depth (Royal Society and Royal Academy of Engineering 2012). However there seems to be consensus that compared to other forms of fuel unconventional gas development water requirements are relatively small (Groat and Grimshaw 2012). The contamination of ground water is particularly a major concern in the southern Karoo. The Karoo has no running water and underground water will have to provide some of the large amounts of water required (Van Staden 2014). Although water, which is saline and probably radioactive, can be obtained from deep within the Dwyka Group in the Karoo, there is a

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possibility that this water can migrate into shallow groundwater aquifers as well as freshwater sources (Van Staden 2014). This could potentially be detrimental to the entire region which is dependent on shallow aquifers for day to day survival (Van Staden 2014). There are also other groundwater contamination concerns which are associated with the hydraulic fracturing water cycle, as hydraulic fracturing fluid can accidentally be released into fresh ground and surface water due to poor well construction, accidents, poor management, spills and leaks (EPA 2011c, EPA 2014). The first study scientifically linking underground water pollution to hydraulic fracturing was released by EPA (2011c) which contradicts the views held by drilling companies. Methane (CH4) is one of the major components of natural gas and 20 times more capable of trapping heat than carbon dioxide (CO2) (EPA 2010). Although natural gas is regarded as a more ecologically friendly fuel compared to coal or oil there is some debate around the greenhouse gas emissions of unconventional gas. However there seems to be a consensus that when generating power from unconventional gas the greenhouse gas impact is much less than when power is generated by coal. Natural gas from unconventional gas development could still help South Africa in meeting its obligations under the UNFCCC and its Kyoto Protocol (South Africa 2011b). Besides greenhouse gas emission, air pollution and the associated health hazards needs to be considered. Natural gas also contains other chemicals such as benzene, alkanes and aromatic hydrocarbons (TREC 2009) which become airborne and when inhaled by humans, over time, can increase the risk of experiencing acute myelogenous leukaemia, irritation of the eyes, acute childhood leukaemia, asthma related symptoms, headaches and multiple myeloma. Earthquakes can also be induced by hydraulic fracturing, primarily due to the injection of fluids into ground formations. Although most seismic events are relatively small and do not cause any damage there have been cases where they have caused damage to property. However the risk associated with seismic activity due to hydraulic fracturing can be mitigated by following 5 simple steps discussed by Zoback (2012). Gas blowouts also occur during hydraulic fracturing or when a water well is installed in an area where hydraulic fracturing was performed (Stag 2008). There is however methods by which blowouts can be prevented such as circulating drilling muds, installing cement casing along the wellbore and then pumping fracturing fluids or the implementation of blow out preventers. Although there are many cases and evidence of air and water pollution, which at this stage generally seems to be problems that are not always specific to hydraulic fracturing but relevant to the upstream oil and gas sector. Regulatory framework needs to be put in place not just to deal with hydraulic fracturing but with the upstream petroleum industry as a whole. New regulation might be required under various statutes. South Africa currently does not have a functional or operations unconventional gas development sector and in order to assess the potential risk data from other countries such as United States of America needs to be used (DMR 2013). Even though unconventional gas development has been extensively embraced and practised in the United States of America the impact that the production process has on the environment is still under continues evaluation (DMR 2013). The materials as well as methods within the unconventional mining process are still developing in order to meet economic as well as public demands. This state of evolution will exists for quite some time as the process is relatively new and all regulations should be structured to growth and learning. There is thus a need to obtain more data on shale resources in order to assess an environmental risks and economic opportunities associated with shale gas extraction. The only way relevant data can be obtained is through exploration and drilling boreholes for

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analysis. Once this has been completed there exist the potential to asses South Africa’s position in a more meaningful manner (DMR 2013). Commercially, technical, regulatory and economically there is significant uncertainties around the unconventional gas development in the southern Karoo. Irrespective of these uncertainties modelling reveals the potential economic and social benefits which could be realised due to the successful development of the shale gas industry in the Karoo. South Africa could become largely independent from coal as a fuel source for power generation and producers will also benefit from the reduction in fuel costs. This could have a positive knock on effect within numerous industries, attract investors and remove the energy restraints on economic growth. Indeed it would be a ‘game-changer’.

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