Thesis (M. Phil.)--University of Hong Kong, 2002. / Includes bibliographical references (leaves 148-149).

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

Current practices in energized treatments, using gases and foams, remain rudimentary in comparison to other fracturing fluid technologies. None of the available 3D fracturing models for incompressible water-based fluids have been able to capture the thermal and compositional effects that are important when using energized fluids, as their constitutive equations assume single-phase, single-component, incompressible fluid flow. These models introduce a bias in fluid selection because they do not accurately capture the unique behavior of energized fluids. The lack of modeling tools specifically suited for these fluids has hindered their design and field implementation. This work uses a fully compositional 3D fracturing model to answer some of the questions surrounding the design of energized treatments. The new model is capable of handling any multi-component mixture of fluids and chemicals. Changes in fluid density, composition, and temperature are predicted using an energy balance equation and an equation of state. A wellbore model, which relates the surface and bottomhole conditions, determines the pumping requirements. Fracture performance is assessed by a fractured well productivity model that accounts for damage in the invaded zone and finite fracture conductivity. The combination of the fracture, productivity, and wellbore models forms a standalone simulator that is suitable for designing and optimizing energized treatments. The simulator offers a wide range of capabilities, making it suitable for many different applications ranging from hydraulic fracturing to long-term injections for enhanced oil recovery, well clean-up, or carbon sequestration purposes. The model is applicable to any well configuration: vertical, deviated, or horizontal. The resolution of the full 3D elasticity problem enables us to propagate the fracture across multiple layers, where height growth is controlled by the vertical distribution of the minimum horizontal stress. We conducted several sensitivity studies to compare the fracture propagation, productivity, and pumping requirements of various fluid candidates in different reservoirs. The results show that good proppant placement and high fracture conductivities can be achieved with foams and gelled fluid formulations. Foams provide a wide range of viscosities without using excessive amounts of gelling agents. They also provide superior fluid-loss control, as the filter-cake is supplemented by the presence of gas bubbles that reduce liquid-flow into the porous medium. CO₂, LPG, and N₂ expand significantly (by 15% or more) as the reservoir heats the fluid inside the fracture. These fluids show virtually no damage in the invaded zone, which is a significant improvement upon water-based fluids in reservoirs that are prone to water blocking. These results, however, are contingent on an accurate fluid characterization supported by experimental data; therefore, our work advocates for complementary experimental studies on fluid rheology, proppant transport, and fluid leak-off. A comprehensive sensitivity study over a wide range of reservoir conditions identified five key reservoir parameters for fluid selection: relative permeability curve, initial gas saturation, reservoir pressure, changes to rock mechanical properties, and water-sensitivity. Because energized fluids provide similar rheology and leak-off behaviors as water-based fluids, the primary design question it to evaluate the extent of the damaged zone against costs, fluid availability, and/or safety hazards. If the fluid-induced damage is acceptable, water-based fluids constitute a simple and attractive solution; otherwise, energized fluids are recommended. Notably, energized fluids are well-suited for reservoirs that are depleted, under-saturated, and/or water-sensitive. These fluids are also favorable in areas with a limited water supply. As water resources become constrained in many areas, reducing the water footprint and the environmental impact is of paramount concern, thereby making the use of energized treatments particularly attractive to replace or subsidize water in the fracturing process. / text

Hydraulic fracturing has unlocked a tremendous resource across the United States and around the world—shale. However, these processes have also come with a myriad of potential environmental effects, including a substantial demand for water. Hydraulic fracturing can require anywhere between two and four million gallons per well. The need for such large quantities of water can produce severe stresses on local water resources. In response to this issue, operators have developed several ways to alleviate some of the stresses brought on by the extensive water use such as alternative sourcing and reuse technologies. Companies are driven to exercise these options and decrease their fresh water usage for hydraulic fracturing processes for multiple reasons, including changes in regulation, to gain support of local communities, and to increase efficiencies of operations. Whatever the motivation may be, there are a variety of options companies have at their disposal to reduce fresh water demands—dependent on specific formation characteristics, the qualities and quantities of available water, among others. The Eagle Ford shale is one of the most rapidly growing shale plays in the country. However, this formation is located in a fairly arid part of the country. Because of meager average rainfall totals, water availability to meet demand is an issue of great concern. Due to nearly exponential increases in shale production, stresses on local water supplies have dramatically increased as well. The objectives of this thesis are as follows: 1) to establish the enormous resource that has become available; while still recognizing the environmental impacts associated with development processes, focusing primarily on water requirements and associated wastewater production; 2) to break down current water demand for shale development, as well as wastewater management practices in the Eagle Ford, with a brief comparison to other shale plays across the country; 3) to obtain an understanding of operator motivation—what factors affect wastewater management strategies; and 4) to analyze techniques operators presently have at their disposal to reduce fresh water demands, specifically through the use of brackish waters and recycling/reuse efforts, and finally to quantify these efforts to evaluate potential fresh water savings. / text

After a fracturing job in a shale reservoir, only a fraction of injected water is recovered. Water is trapped inside the reservoir and reduces the relative permeability of gas. By reducing the interfacial tension between water and hydrocarbon, more water can be recovered thus increasing overall gas production. By adding surfactants into the fracturing fluid, the IFT can be reduced and will help mobilize trapped water. From previous research, two types of surfactant have been identified to be CO₂ soluble. These are the ethoxylated tallow amine and ethoxylated coco amine with varying ethoxylate length. Experiments were performed to test the solubility of these surfactants in water, observe how they change the interaction between HC and water, and measure the IFT reduction between HC and water. Surfactants with more than 10 EO groups were soluble at all salinities, temperature and pH. They also form a non-typical water-in-oil emulsion at all salinities. The surfactants, Ethomeen T/25, T/30, C/15, and C/25 were used in the IFT measurements. They showed interesting trends that exhibit their hydrophilic/hydrophobic nature. These surfactants reduce the IFT between pentane and water to approximately 5 mN/m. The results show that these surfactants do reduce the IFT between water and hydrocarbon, but not as well as conventional EOR surfactants. They do have other added benefits such as being CO₂ soluble, form water in oil emulsions, and tolerant to high temperature and salinity. / text

The recent success in economical production of US shales and other low permeability reservoirs is primarily due to advances in hydraulic fracturing. In this well stimulation technique, a fracturing fluid is injected into the reservoir at pressures high enough to break down the reservoir rock and form fractures. The fractures drain the hydrocarbons in the rock matrix and provide connected pathways for the transport of hydrocarbons to the wellbore. Given the low permeability of the matrix, recent studies of shale gas production suggest that nearly all of the production has to come from a ramified, well-connected network of fractures. A recent study has shown, however, that for reasons yet unknown, the production history of more than 8000 wells in the Barnett Shale can be fit with reasonable accuracy with a linear flow model based on parallel planar hydraulic fractures perpendicular to the wellbore and spaced 1-2 meters apart. The current study is carried out to provide insights into the formation and production properties of complex hydraulic fracture networks. The end goal here is optimization of hydraulic fracture treatments: creating better-connected, more productive fracture networks that can drain the reservoir more quickly. The study provides a mechanistic model of how complexity can emerge in the pattern of hydraulic fracture networks, and describes production from such networks. Invasion percolation has been used in this study to model how the pattern of hydraulic fracture networks develop. The algorithm was chosen because it allows quick testing of different “what if” scenarios while avoiding the high computation cost associated with numerical methods such as the finite element method. The rules that govern the invasion are based on a proposed geo-mechanical model of hydraulic fracture-natural fracture interactions. In the geo-mechanical model, development of fracture networks is modeled as a sequence of basic geo-mechanical events that take place as hydraulic fractures grow and interact with natural fractures. Analytical estimates are provided to predict the occurrence of each event. A complex network of connected fractures is the output of the invasion percolation algorithm and the geo-mechanical model. To predict gas production from the network, this study uses a random walk algorithm. The random walk algorithm was chosen over other numerical methods because of its advantage in handling the complex boundary conditions present in the problem, simplicity, accuracy and speed. / text

A sudden change in flow in a confined system results in the formation of a series of pressure pulses known as a water hammer. Pump shutdown at the conclusion of a hydraulic fracture treatment frequently generates a water hammer, which sends a pressure pulse down the wellbore that interacts with the created fracture before returning towards the surface. This study confirms that created hydraulic fractures alter the period, amplitude, and duration of the water hammer signal. Water hammer pressure signals were simulated with a previously presented numerical model that combined the continuity and momentum equations of the wellbore with a created hydraulic fracture represented by a RCI series circuit. Field data from several multi-stage stimulation treatments were history matched with the numerical model by iteratively altering R, C, and I until an appropriate match was obtained. Equivalent fracture dimensions were calculated from R, C, and I, and were in agreement with acquired micro-seismic SRV. Finally, the obtained R, C, and I values were compared to SRV and production log data. Capacitance was directly correlated with SRV, while resistance was inversely correlated with SRV, and no correlations with production data were observed. / text