Fine grained soils, in particular clays of high plasticity, are known to have very low values of hydraulic conductivity. This low permeability causes several problems related to vegetation growth and stormwater runoff. One way to improve the permeability of clay soils is by using coarse aggregates as a fill material. Recently, Expanded Shale has been widely applied as an amendment to improve drainage properties of clayey soils. However, limited effort has been made to quantify the effect of Expanded Shale on the hydraulic conductivity or on the volume change of fine grained soils. Specifically, the field and laboratory tests required to quantify the amounts of Expanded Shale to be mixed with clays to obtain desired hydraulic conductivity values have not been conducted. This paper presents the results of a series of laboratory fixed-wall permeameter tests conducted on naturally occurring clay deposits in the Austin area with different plasticity. The testing program comprised of clay samples with different quantities of Expanded Shale aggregates by volume, ranging between 0 and 50%, and compacted at two different compaction efforts (60% and 100% of the standard Proctor compaction effort). The laboratory test results indicate that the hydraulic conductivity of the three soils increases by at least an order of magnitude when the Expanded Shale is mixed in quantities between 25 to 30% by volume depending on the compaction effort. Expanded Shale amended samples also showed lower swelling potential with increasing amendment quantities. Moreover, when the clay with the higher plasticity was mixed with 25% Expanded Shale, the compression and recompression ratios decreased by 25% and 15% respectively. / text

The use of hydraulic fracturing has increased rapidly and is now a necessary technique for the development of shale oil and gas resources. However, production rates from these plays typically exhibit high levels of decline. After one year, rates often decrease by over fifty percent. Refracturing – the process of hydraulically fracturing a well that has previously been fractured – is a proposed technique designed to offset these high decline rates and provide a sustainable increase in production. Benefits from refracturing can occur due to a variety of reasons, including the extension of fracture length, the increase in fracture conductivity or the reorientation of the fracture into new areas of the reservoir. In this thesis, the simulation of refracturing treatments on horizontal wells with the use of a diverting agent is described. Diverting agents are used to distribute flow more evenly along the wellbore and to replace the use of costly downhole equipment employed to isolate sections of the wellbore. When diverting agent is deposited, a cake forms with an associated permeability. Flow is diverted from the fractures with high amounts of diverting agent because the larger cake results in a greater resistance to flow. The diverting agent cake breaks down with time at reservoir temperature so that production is uninhibited. Two different models are used to account for the application of diverting agent. One assumes the diverting agent cake forms in the perforation tunnel and the other assumes it forms in the fracture. The propagation of competing fractures is calculated using a computer code developed at the University of Texas called UTWID. In both models, the simulations showed successful diversion of flow. Previously understimulated fractures – that is, shorter fractures or fractures that would grow less preferentially under normal fracturing treatments – grew at a faster pace after pumping of the diverting agent. A sensitivity analysis was conducted on several of the key refracturing design parameters, and the interdependence of the parameters was demonstrated. The simulations support the concept that diverting agents can be used to more evenly stimulate the entire length of the lateral. / text

The vast shale gas and tight oil reservoirs in North America cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures in addition to the disparate in-situ stress conditions in these kinds of formations, microseismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks in the shale plays. In this thesis, an approach is presented, where the fracture networks approximated with microseismic mapping are integrated with a commercial numerical production simulator that discretely models the network structure in both vertical and horizontal wells. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. Two different fracture geometries have been broadly proposed for a multi stage horizontal well, orthogonal and transverse. The orthogonal pattern represents a complex network with cross cutting fractures orthogonal to each other; whereas transverse pattern maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a vii single-stage fracture is further investigated by comparing the propagation of the stage to be dendritic versus planar. A dendritic propagation is bifurcation of the hydraulic fracture due to intersection with the natural fracture (failure along the plane of weakness). The impact of fracture spacing to optimize these fracture geometries is studied. A systematic optimization for designing the fracture length and width is also presented. The simulation is motivated by the oil window of Eagle Ford shale formation and the results of this work illustrate how different fracture network geometries impact well performance, which is critical for improving future horizontal well completions and fracturing strategies in low permeability shale and tight oil reservoirs. A rate transient analysis (RTA) technique employing a rate normalized pressure (RNP) vs. superposition time function (STF) plot is used for the linear flow analysis. The parameters that influence linear flow are analytically derived. It is found that picking a straight line on this curve can lead to erroneous results because multiple solutions exist. A new technique for linear flow analysis is used. The ratio of derivative of inverse production and derivative of square root time is plotted against square root time and the constant derivative region is seen to be indicative of linear flow. The analysis is found to be robust because different simulation cases are modeled and permeability and fracture half-length are estimated. / text

As the development of shale resources continue to accelerate in the United States, improving the effectiveness and the cost efficiency of hydraulic fracturing completion is becoming increasingly important. For such improvement, it is necessary to investigate the effects of various design parameters and in-situ conditions on the resulting fracture dimensions and propagation patterns. In this thesis, a 3D geomechanical model was built using ABAQUS Standard to simulate the propagation of multiple competing fractures in a single fracture stage of a horizontal well. The reservoir was modeled as a porous elastic medium using C3D8RP pore pressure & stress elements. In addition, a vertical plane of COH3D8P pore pressure cohesive elements was inserted at each perforation cluster to model fracture propagation. Also, the flow distribution among perforation clusters was simulated using a parallel resistors model. The results suggested that the fracture spacing has the dominant impact on the number of propagated fractures. Even when all other conditions were favorable to fracture propagation, small fracture spacing reduced the number of propagated fractures. Similarly, in a given fracture stage, decreasing the number of perforation clusters abated inter-fracture stress interference, and increased the number of propagated fractures. Higher injection fluid viscosity significantly increased the fracture widths and slightly decreased the fracture lengths, but did not have any impact on the number of propagated fractures. Also, higher injection rates led to longer and wider fractures, and increased the number of propagated fractures. Therefore, a high injection fluid viscosity and a high injection rate should be used to promote fracture propagation. Lastly, higher Young's modulus of the target formation led to increased stress interference, and the resulting fractures were shorter and narrower. Therefore, if the Young’s modulus of a target formation is high, a wider fracture spacing should be considered. Through this study, a 3D geomechanical model was successfully formulated to simulate the propagation of multiple competing fractures. In addition, the effects of various hydraulic fracturing design parameters and in-situ conditions on the resulting fracture dimensions and propagation patterns were demonstrated. / text

M. Tech. Industrial Engineering / The ability to respond to changes and uncertainty in production demands currently constitutes a crisis in small and medium scale mining industries in South Africa. The case study of various mining and mineral processing site visits which was carried out revealed that the existing conventional screening methods are not scalable or able to be integrated and have limited processing capacity, which constitutes a high production cost on a long-term basis. In view of this, the Reconfigurable Vibrating Screen machine was designed and manufactured with the intension of eliminating these challenges faced by small and medium scale mining industries. The newly developed vibrating screen utilizes the concept of re-configurability, making it simple to attain full capacity processing production on the same machine. The design of a reconfigurable vibrating screen is based on the idea of enhancing the processing capacity by adjustable width and length of the screen structure with regard to the desired processing output.

The goal of the present work is to improve shale reservoir stimulation treatment by using ultra light weight proppants in fracturing fluids. Slickwater has become the most popular fracturing fluid for fracturing shales in recent times because it creates long and skinny fractures and it is relatively cheap. The problem with slickwater is the high rate of settling of common proppants, e.g. sand, which results in propped fractures which are much smaller than the original fractures. Use of gels can help in proppant transport but introduce large formation damage by blocking pores in nano-darcy shales. Gel trapping in the proppant pack causes reduction in permeability of the proppant pack. The light weight proppants which can easily be transported by slickwater and at the same time be able to provide enough fracture conductivity may solve this problem. Three ultra light weight proppants (ULW1, ULW2, and ULW3) have been studied. The mechanical properties of the proppant packs as well as single proppants have been measured. Conductivity of proppant packs has been determined as a function of proppant concentration and confining stress at an average Barnett shale temperature of 95oC. The crush strengths of all the three proppant packs are higher than typical stresses encountered (e.g., Barnett). ULW1 and ULW2 are highly deformable and do not produce many fines. ULW3 has a higher Young’s modulus and produces fines. Conventionally, the proppant conductivity decreases with decreasing proppant concentration and increasing confining stress. But in cases of ULWs, for a partial monolayer, conductivity can be as large as that of a thick proppant pack. The settling velocity is the lowest for ULW1, intermediate for ULW2 and the highest for ULW3. This work contributes new mechanical, conductivity, and settling data on three ultra light weight proppants. Application of light weight proppants in stimulation treatments in shale reservoirs can lead to large propped fractures, which can improve the productivity of fractured shale reservoirs. / text

Recent optimistic revisions to projections for recoverable natural gas resources in the United States have generated renewed interest in the possibility of greater utilization of natural gas as a transportation fuel. Against a backdrop of significant policy challenges for the United States, including air quality concerns in urban areas, slow economic growth and high unemployment, and a rising unease with regard to an increasing dependence on foreign oil; natural gas offers the nation’s transportation sector an opportunity to reduce mobile emissions, lower fuel costs, create jobs and reduce dependence on imported oil. While the current focus for expanded use of natural gas in the transportation sector emphasizes heavy duty and fleet vehicles, there may also be potential for increased use for passenger vehicles. Inconvenience, with regard to refueling, and high incremental vehicle costs, however, are seen as major obstacles to greater adaptation. This analysis examines the benefits and drawbacks of natural gas vehicles from the passenger vehicle perspective and includes data from a cross-country road trip. The report includes a review of market trends and possible development scenarios and concludes with recommendations to minimize the potential challenges of greater adaptation of natural gas vehicles in the passenger vehicle market. / text

The middle Cambrian (Drumian) Rockslide Formation is a deeper-water succession of mixed carbonates and siliciclastics. At the Ravens Throat River location it hosts a Burgess Shale-type (BST) deposit. The BST units are found in two separate 1m thick horizons of green-coloured calcareous mudstone and contain a biota similar to that of the Wheeler and Marjum formations of Utah, and to some extent the Burgess Shale itself. The biota is low in diversity and preserves mainly robust soft-tissue parts. The lithologically heterogeneous composition of the formation (shale, dolomite, lime mudstone, sandstone, mudstone) and absence of metamorphism offer an opportunity to analyze the depositional environment and taphonomy of this deeper water unit. Geochemical analysis including, trace elements, organic carbon, biomarker, and synchrotron were attempted and yielded varying results. Trace element ratios, particularly V/Sc, indicate low oxygenation of the bottom waters during the deposition of the fossil-bearing interval. These results differ from most other BST deposits, which suggest that oxygenated bottom waters were maintained throughout sedimentation. In addition, organic matter in the sediments and δ13Corg values suggest the presence of benthic microbial mats. Silver is concentrated mostly in nm to μm-sized particles in the fossilifereous calcareous mudstone, suggesting elevated levels in the depositional environment. Organic films and the evidence for hyoliths feeding on them suggest an in situ preservation of the biota, perhaps from sudden and short anoxic events and quick burial under either microbial mats or the muddy sediment. This is also supported by the presence of only very rare trace fossils.

An investigation of shale pore structure and compositional/geochemical heterogeneities has been undertaken to elucidate the controls upon gas capacities of potential shale gas reservoirs in northeastern British Columbia, western Canada. Methane sorption isotherms, pore structure and surface area data indicate a complex interrelationship of total organic carbon (TOC) content, mineral matter and thermal maturity affect gas sorption characteristics of Devonian-€”Mississippian (D-€”M) and Jurassic strata. Methane and carbon dioxide sorption capacities of D-€”M shales increase with TOC content, due to the microporous nature of the organic matter. Clay mineral phases arealso capable of sorbing gas to their internal structure; hence D-€”M shales which are both TOC- and clay-rich have the largest micropore volumes and sorption capacities on a dry basis. Jurassic shales, which are invariably less thermally mature than D-€”M shales, do not have micropore volumes which correlate with TOC. The covariance of methane sorption capacity with TOC, independent of micropore volume, indicates a solute gas contribution (within matrix bituminite) to the total gas capacity. On a wt% TOC basis, D-M shales sorb more gas than Jurassic shales: a result of thermal-maturation induced, structural transformation of the D-€”M organic fraction. Organic-rich D-€”M strata are considered to be excellent candidates for gas shales in Western Canada. These strata have TOC contents ranging between 1-5.7 wt%, thermal maturities into the dry-gas region, and thicknesses in places of over 1000 m. Total gas capacity estimates range between 60 and 600 bcf/section where a substantial percentage of the gas capacity is free gas, due to high reservoir temperatures and pressures. Inorganic material influences modal pore size, total porosity and sorption characteristics of D-M shales. Carbonate-rich samples often have lower organic carbon contents (oxic deposition) and porosity, hence potentially lower sorbed and free-gas capacities. Highly mature Devonian shales are both silica and TOC-rich (up to 85% quartz and 5 wt% TOC) and as such, deemed excellent potential shale gas reservoirs because they are both brittle (fracable), and gas-charged. However, quartz-rich Devonian shales display tight-rock characteristics, with poorly developed fabric, small median pore diameters and low permeabilities. Hence potential `frac-zones' will require an increased density of hydraulic fracture networks for optimum gas production.

The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano- pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual porosity models and Darcy’s Law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of complex flow mechanisms occurring in these reservoirs. Through the use of a unique simulator, this research work establishes a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three separate porosity systems: organic matter (mainly kerogen); inorganic matter; and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In the organic matter or kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of smaller pores (mainly nanopores and picopores) and larger pores (mainly micropores and nanopores) in kerogen are incorporated in the simulator. The separate inorganic sub-blocks mainly contribute to the ability to better model dynamic water behavior. The multiple porosity model is built upon a unique tool for simulating general multiple porosity systems in which several porosity systems may be tied to each other through arbitrary transfer functions and connectivities. This new model will allow us to better understand complex flow mechanisms and in turn to extend simulation to the reservoir scale including hydraulic fractures through upscaling techniques