Emulsified acids have been extensively used in the oil industry since 1933. Most of the available research and publications discussed mainly the application of emulsified acid in the field. A fair number of the published work also discussed in depth some of the emulsified acid properties such viscosity, stability and reactivity. However, all of the available research discussed the emulsified acid without sufficient details of its preparation. Beside their chemical composition, the ways emulsified acids are prepared cause significant differences in their physical properties. The characterization of emulsified acid by its droplet size and size distribution complements its chemical composition and gives the emulsified acid a unique description and thus reproducible properties. No previous study considered the impact of the droplet size on the characteristics and properties of emulsified acid. Therefore, the main objective of this research is to study the effects of the droplet size on various properties of emulsified acid such as viscosity, stability and reactivity. Results showed that the droplet size and size distribution have a strong effect on the stability, viscosity and diffusion rate of the emulsified acid. The results of this work are important because knowledge of the effect of the droplet size on major design parameters will guide the way emulsified acid is prepared and applied in the field.

Productivity index (PI) is an important indicator of a well?s production capacity. For conventional reservoirs, well productivity is usually calculated using the pressure response of the reservoir in its pseudosteady-state period. There are numerous studies for different well completion schemes which developed correlations for pseudosteady-state productivity index for specific cases, such as horizontal wells and fractured wells. Most of the developed models for complex well completion schemes use some approximations for productivity index calculation and they have some limitations in use. Furthermore, as the petroleum industry goes toward producing lower quality reservoirs like low- and ultra low-permeability reservoirs, the period of transient flow covers a larger part of the well lifetime and these pseudosteady-state productivity calculations become less applicable in prediction of the reservoir?s production behavior. The Distributed Volumetric Sources (DVS) method seems able to fill this gap. Our method is able to predict the productivity index of a general well completion scheme for transient as well as pseudosteady-state flow periods. In this study, we focus on a typical well completion scheme ? vertical well intersected by a vertical fracture of finite conductivity. Parametric study is performed by varying the proppant pack permeability with a linear distribution, varying fracture width with an elliptical distribution and varying fracture height with an elliptical distribution. The details of hydraulic fracture are integrated into the calculation of well productivity. By combining the well productivity with gas material balance, production forecasting of the hydraulically fractured wells could be easily obtained. The result of production forecasting could be used to aid in decision making of choosing the best stimulation treatment. Field examples are presented to illustrate the application of this technology for production modeling the complicated reservoir cases involving fracture stimulation.

Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 140-146). Available also in a digital version from Dissertation Abstracts.

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

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

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

Slickwater with sand is the most commonly used hydraulic fracturing treatment for shale reservoirs. The slickwater treatment produces long skinny fractures, but only the near wellbore region is propped due to fast settling of sand. Adding gel into water can prevent the fast settling of sand, but gel may damage the fracture surface and proppant pack. Moreover, current water-based fracturing consumes a large amount of water, has high water leakage, and imposes high water disposal costs. The goal of this project is to develop non-damaging, less water-intensive fracturing treatments for shale gas reservoirs with improved proppant placement efficiency. Earlier studies have proposed to replace sand with ultra-light weight proppants (ULWP) to enhance proppant transport, but it is not used commonly in field. This study evaluates the performance of three kinds of ULWPs covering a wide range of specific gravity and representing the three typical manufacturing methods. In addition to replacing sand with ULWPs, replacing water with foams can be an alternative treatment that reduces water usage and decreases proppant settling. Polymer-added foams have been used in conventional reservoirs to improve proppant placement efficiency. However, polymers can damage shale permeability in unconventional reservoirs. This dissertation studies polymer-free foams (PFF) and evaluates their performance. This study uses both experiments and simulations to assess the productivity and profitability of the ULWP treatment and PFF treatment. First, a reservoir simulation model is built in CMG to study the impact of fracture conductivity and propped length on fracture productivity. This model assumes a single fracture intersecting a few reactivated natural fractures. Second, a 2D fracturing model is used to simulate the fracture propagation and proppant transport. Third, strength, API conductivity and gravity settling rates are measured for three ULWPs. Fourth, foam stability tests are conducted to screen the best PFF agents and the selected foams are put into a circulating loop to study their rheology. Finally, empirical correlations from the experiments are applied in the fracturing model and reservoir model to predict productivity by using the ULWPs with slickwater or using the PFFs with sand. Experimental results suggest that, at 4000 psi with concentrations varying from partial monolayer (0.05 lb/ft²) to multilayer (1 lb/ft²), ULW-1 (polymeric) is the most deformable with conductivity of 1-10 md-ft. ULW-2 (resin coated and impregnated ground walnut hull) is the second most deformable with similar conductivity. ULW-3 (resin coated porous ceramic) is the least deformable with conductivity of 20-1000 md-ft, which is comparable to sand. Three foam formulations (A, B: regular surfactant foam, C: viscoelastic surfactant foam) are selected based on the stability results of fourteen surfactants. All PFFs exhibit power-law rheological behavior in a laminar flow regime. The power law parameters of the regular surfactant PFF depend on both quality and pressure when quality is higher than 60% but depend on quality only when quality is lower than 60%. Simulation results suggest that under the optimal concentration of 0.04-0.06 v/v (0.37-0.55 lb/gal) for both ULW-1 and ULW-2, and 0.1 v/v (1.46 lb/gal) for ULW-3, 1-year cumulative production for 0.1 µD shale reservoir is higher than sand by 127% for ULW-1, 28% for ULW-2, and 38% for ULW-3. The productivity benefits decrease as shale permeability increases for all three ULWPs. ULW-1 and ULW-2 have higher productivity benefits for longer production time, while ULW-3 has relatively constant productivity benefits over time. The economic profit of ULW-1 when priced at $5/lb is 2.2 times larger than that of sand for 1-year production in 0.1 µD shale reservoirs; the acceptable maximum price is $10/lb for ULW-1, $6/lb for ULW-2, and $2.5/lb for ULW-3. The maximum price increases as production time increases. The PFFs with a quality of 60% carrying mesh 40 sand at a partial monolayer concentration of 0.04 v/v (0.88 lb/gal) can generate 50% higher productivity, 74% higher economic profit, and over 300% higher water efficiency than the best slickwater-sand case (mesh 40 sand at 0.1 v/v) for 1-year production in 0.1µD shale reservoirs. The benefits of using the PFFs decrease with increasing shale permeability, increasing production time, or decreasing pumping time. This dissertation gives a range of field conditions where the ULWP and PFF may be more effective than slickwater-sand fracturing. / text