Shale gas exploration by means of Hydraulic Fracturing (fracking) has been on the South African (SA) energy agenda since 2010 as a potential alternative energy source to coalmining. Internationally, the desirability of fracking is debated due to increasing evidence of the environmental and health risks fracking poses. However, experts favouring fracking propose this technology as a greener alternative to conventional energy sources such as coal. Limited scientific evidence is available internationally related to knowledge and risk perceptions of fracking and evidence is limited to studies conducted in the United States (US). South African risk perception studies relates to mining, farming, travelling in SA as a foreigner and sexual behaviour. The president of SA called fracking a 'Game-Changer' using industry jargon in the 2014 presidential address. However, SA has failed to produce exploration regulations to date despite oil and gas companies pushing their agendas. Public participation in the process thus far has been limited. This cross sectional study explored the knowledge, health risk perceptions and information sources related to fracking amongst 102 Central Karoo residents through a household survey. Beaufort West municipality was selected as the study site as this is one of the closestareas to Cape Town demarcated for fracking exploration. This study found that 40% of Central Karoo residents do not know what fracking is or the potential risks and benefits thereof. Media is the main information source of 59% of participants. Only half of participants trust their information sources. Those with more trust in their information sources perceived fracking as posing a greater risk. In contrast those believing fracking to pose a low risk were more likely to trust the government and oil and gas companies. More than half of participants (53%) believe that fracking poses an extreme health risk and 78% thought fracking will harm their health. Most commonly listed causes why fracking will make Karoo residents sick includes water pollution (47.4%) and air pollution (19.6%). Higher education was found to have an inverse relationship with trust in the national government A limitation of this study was that farms could not be randomly selected, affecting the representativeness of the sample. There is a major lack of knowledge pertaining to fracking among those living in the Central Karoo which has important implications for managing the process of public participation in the approval of shale gas exploration.

The temporal complexities of anthropogenic Global Climate Change (GCC) force us to extend our moral deliberations beyond what appear to be straightforward, contemporary issues to include the interests of future generations. The Karoo hydraulic fracturing debate is a case in point. The ethical debate thus far has focused on the present-day environmental aspects of Shell’s limited exploratory drilling proposal using hydraulic fracturing technology; but the shale-gas reserves that are believed to underlie the Karoo could assist in mitigating South Africa’s significant carbon emissions, the main contributor to anthropogenic GCC. Thus, I argue that the actual ethical debate is whether to allow gas exploration over the Karoo or to disallow the entire possibility of exploiting any gas reserves that may have been found. A consequentialist weighing up of the respective potential harms to all of the morally-considerable interests involved, including future generations, makes clear that not only is allowing exploration of the Karoo the morally correct decision, but it is ethically obligatory to do so.

Hydraulic fracturing has become increasingly popular in the United States during the last ten years. It is a process that is used for the majority of new oil and gas wells, and is used to access the abundance of natural gas in the US. The largest shale bed is the Marcellus Shale which spans the area underneath many states in the Northeast, primarily New York and Pennsylvania. Policy and science have failed to keep up with the boom in fracking that has occurred across the US, which has led the process to be regulated at varying levels of stringency and a lack of understanding of the potential risks associated with fracking. New York decided that the potential adverse effects of fracking outweighed the economic benefits of job creation and increased tax revenue. New York was the 2nd state in the US that banned fracking, and the decision can be attributed to the unique environmental and political factors present. There were six major environmental reasons that New York decided to ban fracking: decreased respiratory health, drinking water contamination, soil contamination, seismic activity, climate change, and boomtown economic effects. Drinking water contamination is especially important in New York because New York’s reservoirs provide water for over 17 million people. These six environmental factors are not unique to New York, but their impact would be more widely felt than in many other states where fracking occurs. The political factors in New York are also critical to understand. New York is a blue state that is being governed by Governor Cuomo who after his re-election desperately needed to re-align with the left wing of New York’s democratic party. The analysis completed in this paper demonstrates that New York is unique in many ways and the decision to ban hydraulic fracturing there may not be easily replicable in other states.

Hydraulic fracturing is a physically complex phenomenon, and there are many variables, both environmental and operational, that affect the overall success of a fracture treatment. Amongst the operational variables, the process of proppant selection is key to ensuring that the induced fractures remain open and permeable. A variety of physical mechanisms act to degrade the permeability of a given proppant packing after deposition in a fracture, the most important of which is the magnitude of the confining stress. The goal of this work is to understand how mixtures of unlike proppants behave under various stress conditions. Specifically, the permeability and conductivity of various mixtures of unlike proppants are measured as a function of confining stress. A secondary investigation is also made into the dependence of permeability on the areal concentration of proppant. Choices of proppants are restricted to those which are currently most common in industry, in terms of both material and size. To that end, mixtures consisted of primarily ceramics and sands with appropriate grain size distributions. Additionally, a light-weight plastic proppant was included in the study. Simple laboratory methods are employed to measure the permeability of the various proppant packings. Values obtained from direct experimentation are compared with values obtained from an independent analytical model. Given the assumptions which are inherent in the analytical model, the experimental and analytical results are in satisfactory agreement. Also, a correlation is developed for single proppants and binary mixtures which predicts permeability as a function of stress, grain size, material, and weight fraction. One key conclusion is that for a binary mixture of proppants, the mixture permeability will not generally be a weighted linear combination of the pure proppant permeabilities. In other words, the permeability of a mixture comprised of 50% (by weight) of one component and 50% of the second component will generally not be halfway between the permeabilities of the single components. A hypothesis is presented which posits that there are threshold weight fractions for each proppant pair that control the permeability of the mixture. / text

Currently microseismic monitoring is widely used for fracture diagnosis. Since the method monitors the propagation of shear failure events, it is an indirect measure of the propped fracture geometry. Our primary interest is in estimating the orientation and length of the ‘propped’ fractures (not the created fractures), as that is the primary driver for well productivity. This thesis presents a new Low Frequency Electromagnetic Induction (LFEI) method that has the potential to estimate the propped length, height, orientation of hydraulic fractures, and vertical distribution of proppant within the fracture. The proposed technique involves pumping electrically conductive proppant (which is currently available) into the fracture and then using a specially built logging tool to measure the electromagnetic response of the formation. Results are presented for a proposed logging tool that consists of three sets of tri-directional transmitters and receivers at 6, 30 and 60 feet spacing respectively. The solution of Maxwell’s equations shows that it is possible to use the tool to determine both the orientation and the length of the fracture by detecting the location of these particles in the formation after hydraulic fracturing. Results for extensive sensitivity analysis are presented in this thesis to show the effect of different propped lengths, height and orientation of planar fractures in a shale environment. Multiple numerical simulations, using a state-of-the-art electromagnetic simulator (FEKO) indicate, as this work show, that we can detect and map fractures up to 250 feet in length, 0.2 inches wide, and with a 0 to 45 degree of inclination with respect to the wellbore. Special cases such as proppant banking, non-symmetrical bi-wing fractures, and wells with steel casing in place were studied. / text

In this thesis we focus on a novel experimental exploration of fluid-driven fractures in a brittle hydrogel matrix. Fluid-driven fracturing is a procedure by which a fracture is initiated and propagates due to pressure applied by a fluid introduced inside the fracture. We describe how to construct the experimental setup utilised in this research, including how to synthesise polyacrylamide hydrogels to study the processes linked with fluid-driven fracturing. These transparent, linearly elastic and brittle gels permit fracturing at low pressures and speeds allowing accurate measurements to be obtained. The broad range of modulus and fracture energy values attainable from this medium allow the exploration of particular regimes of importance. Fracturing within these hydrogels also creates beautiful spiral patterns on the plastically deformed surfaces. We analyse these patterns and discuss their formation, while also commenting on their fractal-like nature. Initially, we study single fractures that are driven by an incompressible Newtonian fluid, injected at a constant rate into an elastic matrix. The injected fluid creates a radial fracture that propagates along a plane. We investigate this type of fracture theoretically and then verify the scaling predictions experimentally. We examine the rate of radial crack growth, fracture aperture, shape of the crack tip and internal fluid flow field. We exhibit the existence of two distinct fracturing regimes, and the transition between these, in which propagation is either dominated by viscous flow within the fracture or the material toughness. Particle image velocimetry measurements also strikingly show that the flow in the fracture can alter from an expected radial symmetry to circulation cells, dependent on the regime of propagation. We then expand our research to the problem of two coplanar fluid-driven radial fractures. This was chosen to focus on the physical mechanisms that are key to fracture network formation, related to many geophysical and industrial practices. Initially, the two fractures propagate independently of each other. At a critical separation they begin to interact, with non-uniform growth occurring along the fracture edges due to the evolving stress state in the gel matrix. When the radial extents of the fractures become sufficiently large, they coalesce and form a bridge between them. Following initial contact, a large increase in flow is seen into the newly created bridge and most of the growth is localised along this, perpendicular to the line connecting the injection sources. From experimental measurements, we observe a universal dynamic behaviour for the growth of this bridge. We model this universal behaviour theoretically and construct scalings related to the growth after coalescence, which again identifies both a viscous and toughness regime. The toughness regime is verified experimentally for the bridge growth and the universal shape of the thickness profile along the bridge. The coalesced fractures then transition into a single fracture at late times. Finally, we discuss a number of other interesting scenarios that may occur such as, non-coalescing fractures, asymmetric coalescence and ridge formation.

Successful development of shale gas reservoirs is highly dependent on hydraulic fracture treatments. Many questions remain in regards to the geometry of the created fractures. Production data analysis from some shale gas wells quantifies a much smaller stimulated pore volume than what would be expected from microseismic evidence and reports of fracturing fluids reaching distant wells. In addition, claims that hydraulic fracturing may open or reopen a network of natural fractures is of particular interest. This study examines hydraulic fracturing of shale gas formations with specific interest in fracture geometry. Several field cases are analyzed using microseismic analysis as well as net pressure analysis of the fracture treatment. Fracture half lengths implied by microseismic events for some of the stages are several thousand feet in length. The resulting dimensions from microseismic analysis are used for calibration of the treatment model. The fracture profile showing created and propped fracture geometry illustrates that it is not possible to reach the full fracture geometry implied by microseismic given the finite amount of fluid and proppant that was pumped. The model does show however that the created geometry appears to be much larger than half the well spacing. From a productivity standpoint, the fracture will not drain a volume more than that contained in half of the well spacing. This suggests that for the case of closely spaced wells, the treatment size should be reduced to a maximum of half the well spacing. This study will provide a framework for understanding hydraulic fracture treatments in shale formations. In addition, the results from this study can be used to optimize hydraulic fracture treatment design. Excessively large treatments may represent a less than optimal approach for developing these resources.

The distributions of pore pressure and stresses around a fracture are of interest in conventional hydraulic fracturing operations, fracturing during water-flooding of petroleum reservoirs, shale gas, and injection/extraction operations in a geothermal reservoir. During the operations, the pore pressure will increase with fluid injection into the fracture and leak off to surround the formation. The pore pressure increase will induce the stress variations around the fracture surface. This can cause the slip of weakness planes in the formation and cause the variation of the permeability in the reservoir. Therefore, the investigation on the pore pressure and stress variations around a hydraulic fracture in petroleum and geothermal reservoirs has practical applications. The stress and pore pressure fields around a fracture are affected by: poroelastic, thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stress. In our study, we built up two models. One is a model (WFPSD model) of water-flood induced fracturing from a single well in an infinite reservoir. WFPSD model calculates the length of a water flood fracture and the extent of the cooled and flooded zones. The second model (FracJStim model) calculates the stress and pore pressure distribution around a fracture of a given length under the action of applied internal pressure and in-situ stresses as well as their variation due to cooling and pore pressure changes. In our FracJStim model, the Structural Permeability Diagram is used to estimate the required additional pore pressure to reactivate the joints in the rock formations of the reservoir. By estimating the failed reservoir volume and comparing with the actual stimulated reservoir volume, the enhanced reservoir permeability in the stimulated zone can be estimated. In our research, the traditional two dimensional hydraulic fracturing propagation models are reviewed, the propagation and recession of a poroelastic PKN hydraulic fracturing model are studied, and the pore pressure and stress distributions around a hydraulically induced fracture are calculated and plotted at a specific time. The pore pressure and stress distributions are used to estimate the failure potentials of the joints in rock formations around the hydraulic fracture. The joint slips and rock failure result in permeability change which can be calculated under certain conditions. As a case study and verification step, the failure of rock mass around a hydraulic fracture for the stimulation of Barnett Shale is considered. With the simulations using our models, the pore pressure and poro-induced stresses around a hydraulic fracture are elliptically distributed near the fracture. From the case study on Barnett Shale, the required additional pore pressure is about 0.06 psi/ft. With the given treatment pressure, the enhanced permeability after the stimulation of hydraulic fracture is calculated and plotted. And the results can be verified by previous work by Palmer, Moschovidis and Cameron in 2007.

Multiple transverse fracturing along a horizontal well is a relatively new technology that is designed to increase well productivity by increasing the contact between the reservoir and the wellbore. For multiple transverse fractures, the performance of the well system is determined by three aspects: the inflow from the reservoir to the fracture, the flow from the fracture to the wellbore, and the inflow from the reservoir to the horizontal wellbore. These three aspects influence each other and combined, influence the wellbore outflow. In this study, we develop a model to effectively formulate the inter-relationships of a multi-fracture system. This model includes a reservoir model and a wellbore model. The reservoir model is established to calculate both independent and inter-fracture productivity index to quantify the contribution from all fractures on pressure drop of each fracture, by using the source functions to solve the single-phase gas reservoir flow model. The wellbore model is used to calculate the pressure distribution along the wellbore and the relationship of pressure between neighboring fractures, based on the basic pressure drop model derived from the mechanical energy balance. A set of equations with exactly the same number of fractures will be formed to model the system by integrating the two models. Because the equations are nonlinear, iteration method is used to solve them. With our integrated reservoir and wellbore model, we conduct a field study to find the best strategy to develop the field by hydraulic fracturing. The influence of reservoir size, horizontal and vertical permeability, well placement, and fracture orientation, type (longitudinal and transverse), number and distribution are completely examined in this study. For any specific field, a rigorous step-by-step procedure is proposed to optimize the field.

Hydraulic fracturing of a naturally-fractured reservoir is a challenge for industry, as fractures can have complex growth patterns when propagating in systems of natural fractures in the reservoir. Fracture propagation near a natural fracture (NF) considering interaction between a hydraulic fracture (HF) and a pre-existing NF, has been investigated comprehensively using a two dimensional Displacement Discontinuity Method (DDM) Model in this thesis. The rock is first considered as an elastic impermeable medium (with no leakoff), and then the effects of pore pressure change as a result of leakoff of fracturing fluid are considered. A uniform pressure fluid model and a Newtonian fluid flow model are used to calculate the fluid flow, fluid pressure and width distribution along the fracture. Joint elements are implemented to describe different NF contact modes (stick, slip, and open mode). The structural criterion is used for predicting the direction and mode of fracture propagation. The numerical model was used to first examine the mechanical response of the NF to predict potential reactivation of the NF and the resultant probable location for fracture re-initiation. Results demonstrate that: 1) Before the HF reaches a NF, the possibility of fracture re-initiation across the NF and with an offset is enhanced when the NF has weaker interfaces; 2) During the stage of fluid infiltration along the NF, a maximum tensile stress peak can be generated at the end of the opening zone along the NF ahead of the fluid front; 3) Poroelastic effects, arising from fluid diffusion into the rock deformation can induce closure and compressive stress at the center of the NF ahead of the HF tip before HF arrival. Upon coalescence when fluid flows along the NF, the poroelastic effects tend to reduce the value of the HF aperture and this decreases the tension peak and the possibility of fracture re-initiation with time. Next, HF trajectories near a NF were examined prior to coalesce with the NF using different joint, rock and fluid properties. Our analysis shows that: 1) Hydraulic fracture trajectories near a NF may bend and deviate from the direction of the maximum horizontal stress when using a joint model that includes initial joint deformation; 2) Hydraulic fractures propagating with higher injection rate or fracturing fluid of higher viscosity propagate longer distance when turning to the direction of maximum horizontal stress; 3) Fracture trajectories are less dependent on injection rate or fluid viscosity when using a joint model that includes initial joint deformation; whereas, they are more dominated by injection rate and fluid viscosity when using a joint model that excludes initial joint deformation.