Browsing by Subject "Fracturing"
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Item Analysis and interpretation of a hydraulic fracture treatment using offset vertical observation wells and a hydraulic fracture simulator(2015-08) Griffith, Christopher Adam; McClure, Mark W. (Mark William); Espinoza, NicolasAnalysis of hydraulic fracture treatments requires incorporating a wide range of data in order to make useful inferences about fracture properties. For example, microseismic monitoring and production decline analysis can be used to obtain the hydraulic fracture half-length, which is an important parameter for field development. The challenge in using these tools is that the methods used for analysis are open to interpretation and can make it difficult to rely on the results. This thesis integrates data from four horizontal wells that were hydraulically fractured in an unconventional shale play and results from a 2-dimensional hydraulic fracture simulator in order to make qualitative observations about fracture properties. The importance of the data set hinges on nine vertical observation wells that recorded pressure vs. time during the hydraulic fracture treatments. The observation wells were located at different distances and depths from the horizontal wells. This is important because it removes some of the ambiguity associated with making interpretations from microseismic data, production decline analysis, or other methods. Results from modeling and the data set indicated the following: (1) the networks of fractures created from these treatments were volumetric and complex, illustrated by the microseismic data and the pressure signals recorded at the observation wells, (2) microseismicity was generally successful in delineating where fluid progressed during pumping, (3) however, flow of fluid into fractures stimulated during previous stages was aseismic, a manifestation of the Kaiser effect, and (4) during long term production, fluid was not produced from the more distant parts of the reservoir that were pressurized and stimulated during the fracturing treatment. To explain these four observations, we hypothesize that proppant was not transported to the regions of the stimulated rock volume that were most distant from the stimulated wells. The stimulated, but unpropped, fractures in this region evidently lost much of their conductivity after closure that they did not contribute significantly to long term production.Item Development of a hydrate-gas-water static equilibrium model and analysis of three-phase stability(2018-05) Leung, Ryan Wai-Hung; Daigle, HughRecent evidence suggests that a three-phase stability zone exists at the base of gas hydrate stability (BGHS), where hydrate and gas may coexist due to the pore size distribution. We develop a three-phase stability zone model at static equilibrium based on the idea of minimizing interfacial energy. We use this model to produce three-phase saturations and study the effects of three-phase stability for two applications. The first application is related to the migration of gas from beneath sealing hydrate layers to the seafloor. A proposed mechanism for this upwards gas migration is the generation of fractures through the sealing hydrate sediment due to overpressures caused by the accumulation of gas on geologic timescales. Our study focuses on how the fracturing potential of a three-phase stability zone differs from a discrete BGHS, where hydrate is separated from gas by a sharp boundary. We model gas overpressures at Blake Ridge, Hydrate Ridge, and the Kumano Basin by incorporating mercury intrusion capillary pressure data with our three-phase stability model. Our results show that the overpressures in the three-phase stability model are smaller, reducing the potential for gas-driven fracturing. We also find that hydrate-bearing basins with shallower seafloor depths modeled with three-phase stability need much more methane to generate the overpressures that will initiate fractures. The second application of three-phase stability relates to the bottom-simulating reflection (BSR), which is a common negative polarity reflection in marine sediments that often follows the contour of the seafloor. Recent literature suggests that the BSR indicates the shallowest presence of gas, not the BGHS. This three-phase stability model has an impact on the seismic response of the BSR, and we study this effect by developing 1-D rock physics models of Blake Ridge. By varying the methane quantity and performing fluid substitution with three-phase saturation profiles, we generate synthetic seismograms and analyze the difference in two way travel time (TWTT). For comparison, we use the workflow for a parameter sensitivity model and an original-resolution model. Through this analysis, we find a relationship between the TWTT width of the BSR’s peaks and the methane abundance at the BGHSItem Evaluation of friction reducers for use in recycle fracturing flowback and produced water(2014-05) Kuzmyak, Nicholas John; Katz, Lynn Ellen; Oort, Eric vanThe continued expansion of hydraulic fracturing activity in North America -- especially in slickwater operations -- has given rise to concerns regarding water quantity and quality. On one hand, operators in arid areas must compete with other users to obtain enough fresh water to perform fracturing operations, while in other areas the flowback water after a treatment must be either expensively treated or disposed of in injection wells, which are in very limited supply in regions such as the Marcellus Shale. Reuse of these highly saline waters can help to alleviate both of these problems. However, water that contains concentrated and difficult-to-remove salt ions -- especially divalent cations -- cannot be used with typical polyacrylamide friction reducers, due to these additives' dramatically decreased effectiveness in such fluids. Otherwise, reuse would be an attractive option and, in fact, this practice is widespread in multiple US shale plays with the recent advent of salt-tolerant polyacrylamides. This research attempts to quantify the effect of high salt concentrations on the effectiveness of friction reducers through construction of a flow loop apparatus that allows for observation of turbulent drag reduction. The polymers tested were chosen from industry standards (inverse oil-emulsion salt-tolerant anionic polyacrylamide), novel polyacrylamides (highly salt-tolerant polyacrylamide dispersed in concentrated brine), and an overlooked yet potentially highly effective polymer (i.e. polyethylene oxides, PEOs). PEOs, in particular, have been known as highly efficient friction reducers in brines for over 50 years, but are not used in the fracturing industry for various reasons. These three additives were tested at concentrations of 0.1% in solutions of sodium chloride, calcium chloride, and a multisolute brine of both salts. The experiments show that the typical salt-tolerant polyacrylamide is indeed negatively affected by the divalent calcium ions, while the novel polyacrylamide is a strong performer (up to 60% friction reduction) in even the strongest brines. Interestingly, the PEOs consistently produced about 45% friction reduction (based on the base fluid pipe friction pressure drop), and did so at low concentrations (<0.1%) for a range of molecular weights. The major conclusion of this research is that even highly concentrated brine can be recycled with minimal treatment if either the novel polyacrylamide or PEOs are used, opening the door for potential use of other atypical brine sources in hydraulic fracturing operations. The PEOs are especially interesting because, though overlooked, they are economical, readily available, and salt-tolerant. Future experiments will be run on a larger flow loop to potentially optimize PEO characteristics and further demonstrate their viability as an alternative to polyacrylamides.Item Examining the effect of cemented natural fractures on hydraulic fracture propagation in hydrostone block experiments(2012-08) Bahorich, Benjamin Lee; Olson, Jon E.; Holder, JonMicro seismic data and coring studies suggest that hydraulic fractures interact heavily with natural fractures creating complex fracture networks in naturally fractured reservoirs such as the Barnett shale, the Eagle Ford shale, and the Marcellus shale. However, since direct observations of subsurface hydraulic fracture geometries are incomplete or nonexistent, we look to properly scaled experimental research and computer modeling based on realistic assumptions to help us understand fracture intersection geometries. Most experimental analysis of this problem has focused on natural fractures with frictional interfaces. However, core observations from the Barnett and other shale plays suggest that natural fractures are largely cemented. To examine hydraulic fracture interactions with cemented natural fractures, we performed 9 hydraulic fracturing experiments in gypsum cement blocks that contained embedded planar glass, sandstone, and plaster discontinuities which acted as proxies for cemented natural fractures. There were three main fracture intersection geometries observed in our experimental program. 1) A hydraulic fracture is diverted into a different propagation path(s) along a natural fracture. 2) A taller hydraulic fracture bypasses a shorter natural fracture by propagating around it via height growth while also separating the weakly bonded interface between the natural fracture and the host rock. 3) A hydraulic fracture bypasses a natural fracture and also diverts down it to form separate fractures. The three main factors that seemed to have the strongest influence on fracture intersection geometry were the angle of intersection, the ratio of hydraulic fracture height to natural fracture height, and the differential stress. Our results show that bypass, separation of weakly bonded interfaces, diversion, and mixed mode propagation are likely in hydraulic fracture intersections with cemented natural fractures. The impact of this finding is that we need fully 3D computer models capable of accounting for bypass and mixed mode I-III fracture propagation in order to realistically simulate subsurface hydraulic fracture geometries.Item A general poro-elastic model for pad-scale fracturing of horizontal wells(2015-12) Manchanda, Ripudaman; Sharma, Mukul M.; Espinoza, David N; McClure, Mark W; Olson, Jon E; Roussel, Nicolas PEconomic production of oil and gas from tight rocks requires horizontal well drilling with multiple hydraulic fractures along the length of the horizontal wells. Multiple horizontal wells are drilled and fractured close to each other to increase the recovery of oil and gas from a single location or pad. Interference between fractures in a horizontal well pad is commonly observed in the field. There is no clear understanding of the impact of various operational and reservoir parameters on the observed interference. This inter-well interference can occur through the creation of complex fracture networks and/or poro-elastic stress changes. In this research, the development of a poro-elastic numerical simulator was undertaken to evaluate hydraulic fracturing practices in pad-scale scenarios. The primary motivation was to assess the impact of various operational parameters such as fracture spacing, well spacing and fracture sequencing on the geometry of the created fractures. Two approaches were used to understand the problem at hand. In the first approach, static fractures were simulated in 3-D and the impact of their stress shadow on subsequent fractures was studied. It was observed that fracture spacing, injection volume, and time between successive fractures were the most important parameters that could be used to optimize the creation of fractures in a well. Formation properties such as Young’s modulus and horizontal stress contrast modified the magnitude and spatial extent of the stress shadow and the extent of stress reorientation. It was shown that stage spacing, well spacing and fracture sequencing together with fracture designs (volume of sand pumped and fluids used) can be adjusted to obtain non-intersecting, transverse fractures that efficiently drain the reservoir. A hypothesis, time dependent closure of induced unpropped fractures, was presented to explain why zipper fracturing often outperforms conventional sequential fracturing. The hypothesis was tested and confirmed with a field data set made available to us by Shell from the Eagle Ford shale. In the second approach, a novel finite volume based 3-D, geomechanical, field-scale numerical simulator was developed to simulate propagation of multiple fractures simultaneously in a poro-elastic reservoir. This provided a more realistic model of the pad-scale fracturing process. The ability of the model to perform realistic pad-scale simulations was demonstrated for a variety of field situations such as multi-cluster multi-stage fracturing, infill-well fracturing, re-fracturing, mini-frac analysis and fracture network simulations. The inclusion of poro-elastic effects and reservoir heterogeneity in the model allowed us to examine the effects of reservoir depletion on fracture geometry in refraced and infill wells.Item Hydraulic fracturing in naturally fractured reservoirs and the impact of geomechanics on microseismicity(2011-12) Yadav, Himanshu; Sharma, Mukul M.; Olson, Jon E.Hydraulic fracturing in tight gas and shale gas reservoirs is an essential stimulation technique for production enhancement. Often, hydraulic fracturing induces fracture patterns that are more complex than the planar geometry that has been assumed in the past models. These complex patterns arise as a result of the presence of planes of weakness, faults and/or natural fractures. In this thesis, two different 3D geomechanical models have been developed to simulate the interaction between the hydraulic fracture and the natural fractures, and to observe the impact of geomechanics on the potential microseismicity in these naturally fractured formations. Several cases were studied to observe the effects of natural fracture geometry, fracturing treatment, mechanical properties of the sealed fractures, etc. on the propagation path of the hydraulic fracture in these formations, and were found to be consistent with past experimental results. Moreover, the effects of several parameters including cohesiveness of the sealed natural fractures, mechanical properties of the formation, treatment parameters, etc. have been studied from the potential microseismicity standpoint. It is shown that the impact of geomechanics on potential microseismicity is significant and can influence the desired fracture spacing. In this thesis, the presented model quantifies the extent of potential microseismic volume (MSV) resulting from hydraulic fracturing in unconventional reservoirs. The model accounts for random geometries of the weak planes (with different dip and strike) observed in the field. The work presented here shows, for the first time, a fracture treatment can be designed to maximize the MSV, when the fractures form a complicated network of fractures, and in turn influence the desired fracture spacing in horizontal wells. Our work shows that by adjusting the fluid rheology and other treatment parameters, the spatial extent of MSV and the desired fracture spacing can be optimized for a given set of shale properties.Item Hydraulic fracturing optimization : experimental investigation of multiple fracture growth homogeneity via perforation cluster distribution(2016-05) Michael, Andreas; Olson, Jon E.; Balhoff, Matthew THydraulic fracturing is a reservoir stimulation technique used in the petroleum industry since 1947. High pressure fluid composed mainly of water generates cracks near the wellbore improving the surrounding permeability and enhancing the flow of oil and gas to the surface. Advances in hydraulic fracturing coupled with developments in horizontal drilling, have unlocked vast quantities of unconventional resources, previously believed impossible to be produced. Fracture creation induces perturbations in the nearby in-situ stress regime suppressing the initiation and propagation of other fractures. Neighboring fractures are affected by this stress shadow effect, causing them to grow dissimilarly and they receive unequal portions of the injected fluid. Numerical simulation models have shown that non-uniform perforation cluster distributions with interior fractures closer to the exterior ones can balance out these stress shadow effects, promoting more homogeneous multiple fracture growth compared to uniform perforation cluster distributions. In this work, laboratory-scale tests on three perforation configurations are performed on transparent specimens using distinctly colored fracturing fluids such that fracture growth can be observed. A normal faulting stress regime is replicated with the introduction of an overburden load in a confined space. The results have shown that uniform perforation spacing configurations yields higher degree of fracture growth homogeneity, as maximum spacing minimizes stress shadow effects, compared to moving the middle perforation closer to the toe, or heel of the horizontal well. The experiments also showed a proclivity to form one dominant fracture. Time delay, neglected in most theoretical modelling studies, between fracture initiations is found to be a key parameter and is believed to be one of the major factors promoting this dominant fracture tendency along with wellbore pressure gradients. Moreover, in several cases, the injected bypassed perforation(s) to generate fracture(s) downstream. Finally, the compressibility of the fracturing fluid triggered somewhat unexpected transient pressure behavior. The understanding of the stress shadow effects and what influences them could lead to optimization of hydraulic fracturing treatment design in terms of productivity and cost. Therefore, achieving more homogeneous multiple fracture growth patterns can be pivotal on the economic feasibility of several stimulation treatments.Item Productivity Improvement of Gas-Condensate Wells by Fracturing(2000-08) Rajeev, Kumar; Pope, Gary A.; Sharma, Mukul ManiThe objective of this thesis was to study the effect of vertical fractures in improving the productivity of gas-condensate wells by conducting numerical simulations. A single-well fracture-model, that includes a hydraulic fracture, was simulated using UTCOMP compositional simulator. The results show that a vertical fracture can significantly help in recovering the loss of productivity that occurs because of the condensate dropout near the wellbore. Effect of various factors such as fracture length, fracture conductivity, formation permeability, gas relative permeability, production mode, gas composition, and permeability heterogeneity was studied. It is demonstrated that the gas-condensate well productivity can be theoretically improved by a factor of eight by creating idealized (long and highly conductive) vertical fractures. The effect of formation permeability is also analyzed. It is demonstrated that high-: permeability reservoirs encounter lower amount of condensate accumulation near the wellbore, and thus, lower extent of productivity decline, compared to low-permeability reservoirs. The effect of production mode - i.e., constant-rate versus constant-bottomhole-pressure production has been analyzed. Also, the effect of gas-relative-permeability endpoint was studied. A simulation study of the effect of gas composition on well productivity was performed. Two gases of very different compositions, one - a case of highly rich gas, and the other, a case of highly lean gas were studied. It is demonstrated that the productivity decline in these two cases is not significantly different, although the calculated liquid-dropouts being significantly different. It is to be noted that the above conclusions are based on the results of a set of simulations performed for a short period of time and with limited rate of production. A simulation study of permeability heterogeneity was performed. This preliminary study demonstrated that the effect of permeability heterogeneity on the gas-condensate well productivity is very significant. It also clearly shows that this is a complex problem and needs a thorough analysis of all the parameters involved.Item Simultaneous propagation of multiple fractures in a horizontal well(2013-08) Shin, Do H; Sharma, Mukul M.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.Item Study on the feasibility of using electromagnetic methods for fracture diagnostics(2012-08) Saliés, Natália Gastão; Sharma, Mukul M.; Ling, HaoThis thesis explores two ways of developing a fracture diagnostics tool capable of estimating hydraulic fracture propped length and orientation. Both approaches make use of an electrically conductive proppant. The fabrication of an electrically conductive proppant is believed to be possible and an option currently on the market is calcined petroleum coke. The first approach for tool development was based on principles of antenna resonance whereas the second approach was based on low frequency magnetic induction. The former approach had limited success due to the lack of resonant features at the stipulated operating conditions. Low frequency induction is a more promising approach as electromagnetic fields showed measurable changes that were dependent on fracture length in simulations. The operation of a logging tool was simulated and the data showed differences in the magnetic field magnitude ranging from 2% to 107% between fracture sizes of 20m, 50m, 80m, and 100m. Continuing research of the topic should focus not only on simulating more diverse fracture scenarios but also on developing an inversion scheme necessary for interpreting field data.Item Surfactant characterization to improve water recovery in shale gas reservoirs(2013-12) Huynh, Uyen T.; Nguyen, Quoc P.; DiCarlo, David Anthony, 1969-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.