Browsing by Subject "Unconventional reservoirs"
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Item A probabilistic workflow for uncertainty analysis using a proxy-based approach applied to tight reservoir simulation studies(2016-08) Wantawin, Marut; Sepehrnoori, Kamy, 1951-; Yu, WeiUncertainty associated with reservoir simulation studies should be thoroughly captured during history matching process and adequately explained during production forecasts. Lacking information and limited accuracy of measurements typically cause uncertain reservoir properties in the reservoir simulation models. Unconventional tight reservoirs, for instances, often deal with complex dynamic flow behavior and inexact dimensions of hydraulic fractures that directly affect production estimation. Non-unique history matching solutions on the basis of probabilistic logic are recognized in order to avoid underestimating prediction results. Assisted history matching techniques have been widely proposed in many literature to quantify the uncertainty. However, few applications were done in unconventional reservoirs where some distinct uncertain factors could significantly influence well performance. In this thesis, a probabilistic workflow was developed using proxy-modeling approach to encompass uncertain parameters of unconventional reservoirs and obtain reliable prediction. Proxy-models were constructed by Design of Experiments (DoE) and Response Surface Methodology (RSM). As preliminary screening tools, significant parameters were identified, thus removing those that were insignificant for the reduced dimensions. Furthermore, proxy-models were systematically built to approximate the actual simulation, then sampling algorithms, e.g. Markov Chain Monte Carlo (MCMC) method, successfully estimated probabilistic history matching solutions. An iterative procedure was also introduced to gradually improve the accuracy of proxy-models at the interested region with low history matching errors. The workflow was applied to case studies in Middle Bakken reservoir and Marcellus Shale formation. In addition to estimating misfit function for the errors, proxy-models are also regressed on the simulated quantity of the measurements at various points in time, which is shown to be very useful. This alternative method was utilized in a synthetic tight reservoir model, which analyzed the impact of complex fracture network relative to instantaneous well performance at different stages. The results in this thesis show that the proxy-based approach reasonably provides simplified approximation of actual simulation. Besides, they are very flexible and practical for demonstrating the non-unique history matching solutions and analyzing the probability distributions of complicated reservoir and fracture properties. Ultimately, the developed workflow delivers probabilistic production forecasts with efficient computational requirement.Item A three-dimensional simulation of triaxial test on Mancos Shale using peridynamics and the microplane constitutive model (M7)(2023-08-16) Suaid, Mohammed Ahmad; Foster, John T., Ph. D.; Balhoff, Matthew TAs the petroleum industry aligns its vision with that of the fourth industrial revolution, modeling and simulation of traditional laboratory experiments may have a significant impact on process optimization and cutting costs. Therefore, this thesis aims to simulate the triaxial test, a crucial experiment in geomechanics laboratories that helps with understanding rocks’ properties and for constitutive model calibration. Once calibrated, a geomechanical constitutive model can be used in designing hydraulic fracturing operations or for wellbore stability analysis. Hydraulic fracture completions are typically used in unconventional reservoir rocks for the production of oil and natural gas, like Mancos Shale, whose rock samples are chosen to be a subject in these simulations due to its anisotropy and heterogeneity. This thesis provides a methodology to create a model that simulates the triaxial test using the microplane constitutive model (M7) paired with peridynamics as a simulation technology. We use the Peridigm code, a massively-parallel peridynamics analysis software for simulation of fracturing and fragmentation. The simulations are partially validated by analytical solutions and calibrated against triaxial experiments. After additional development of the software with a few additional algorithms, it was able to run as if a triaxial test was being conducted, allowing the user to freely adjust parameters such as confining pressure and axial loads. As a part of this project, stress versus strain plots are generated using post-processing scripts in order to calculate the error between simulation data and literature data utilizing an objective function, hence supporting the calibration process of the model. In this thesis, several important aspects are discussed, such as the significant role of natural gas in the future energy landscape, the quantification of anisotropy in Mancos Shale, the mechanics of triaxial test apparatus, the theory of peridynamics, and the microplane constitutive model (M7).Item Analyzing pressure interference between fractured wells in unconventional reservoirs(2020-11-29) Seth, Puneet; Sharma, Mukul M.; Mohanty, Kishore; Foster, John T; DiCarlo, David A; Roussel, Nicolas PIn conventional reservoirs, pressure transient analysis has been well studied and is based on hydraulic diffusion in the reservoir. In such high permeability reservoirs, pressure interference tests have been widely used to gather information about inter-well communication and reservoir permeability in the vicinity of the tested wells. However, in unconventional ultra-low permeability reservoirs (100 nD - 1μD), hydraulic diffusion through the reservoir matrix is negligible, instead poroelastic deformation of the rock dominates the pressure transient response. This renders traditional pressure interference analyses and well testing techniques ineffective in unconventional reservoirs. Horizontal wells drilled in unconventional reservoirs are hydraulically fractured during multiple stages of injection to increase the surface area available for production of hydrocarbons from these reservoirs, and similar to conventional reservoirs, pressure interference is often observed between fractured wells drilled in close proximity in unconventional reservoirs. However, unlike conventional reservoirs, pressure interference between fractured wells in unconventional reservoirs is not well understood. In this research, pressure interference between fractured wells in unconventional reservoirs is analyzed by developing numerical simulation models and investigating field data to understand the mechanisms that result in pressure communication between fractured wells, both during stimulation and production. Additionally, pressure interference analysis has been applied as a fracture diagnostics technique to investigate real field scenarios at multiple locations (Hydraulic Fracturing Test Site #1, DJ Basin and Permian Basin). A 3-D, fully-coupled geomechanical model that can simulate fracture propagation from the treatment well while monitoring pressure changes inside a compliant fracture in a nearby offset well has been developed. Numerical simulations and field data analyses show that in unconventional reservoirs, pressure interference between fractured wells is caused either by reservoir stress alterations during hydraulic fracture propagation, or high-permeability fracture connections (hydraulic communication) between the wells. The application of pressure interference analysis to diagnose inter-well communication during production and as a fracture diagnostics tool during stimulation to estimate fracture geometry, SRV permeability, diagnose diversion effectiveness and stimulation efficiency is demonstrated. Compared to other techniques such as micro-seismic monitoring and fiber optics that are expensive and require additional equipment, pressure interference analysis is presented as a novel and inexpensive tool that enables fracture diagnostics during both production and stimulation in unconventional reservoirsItem Assisted history matching workflow for unconventional reservoirs(2019-05-13) Tripoppoom, Sutthaporn; Sepehrnoori, Kamy, 1951-The information of fractures geometry and reservoir properties can be retrieved from the production data, which is always available at no additional cost. However, in unconventional reservoirs, it is insufficient to obtain only one realization because the non-uniqueness of history matching and subsurface uncertainties cannot be captured. Therefore, the objective of this study is to obtain multiple realizations in shale reservoirs by adopting Assisted History Matching (AHM). We used multiple proxy-based Markov Chain Monte Carlo (MCMC) algorithm and Embedded Discrete Fracture Model (EDFM) to perform AHM. The reason is that MCMC has benefits of quantifying uncertainty without bias or being trapped in any local minima. Also, using MCMC with proxy model unlocks the limitation of an infeasible number of simulations required by a traditional MCMC algorithm. For fractures modeling, EDFM can mimic fractures flow behavior with a higher computational efficiency than a traditional local grid refinement (LGR) method and more accuracy than the continuum approach. We applied the AHM workflow to actual shale gas wells. We found that the algorithm can find multiple history matching solutions and quantify the fractures and reservoir properties posterior distributions. Then, we predicted the production probabilistically. Moreover, we investigated the performance of neural network (NN) and k-nearest neighbors (KNN) as a proxy model in the proxy-based MCMC algorithm. We found that NN performed better in term of accuracy than KNN but NN required twice running time of KNN. Lastly, we studied the effect of enhanced permeability area (EPA) and natural fractures existence on the history matching solutions and production forecast. We concluded that we would over-predict fracture geometries and properties and estimated ultimate recovery (EUR) if we assumed no EPA or no natural fractures even though they actually existed. The degree of over-prediction depends on fractures and reservoir properties, EPA and natural fractures properties, which can only be quantified after performing AHM. The benefits from this study are that we can characterize fractures geometry, reservoir properties, and natural fractures in a probabilistic manner. These multiple realizations can be further used for a probabilistic production forecast, future fracturing design improvement, and infill well placement decision.Item Characterization of bedding-parallel fractures in shale : morphology, size distribution and spatial organization(2016-12) Wang, Qiqi; Laubach, Stephen E. (Stephen Ernest), 1955-; Gale, Julia F. W.Natural fracture systems are important for production in shale gas reservoirs as they may contribute to permeability of the reservoir, or they may reactivate during hydraulic fracture treatment. However, little is known about their size scaling and spatial distribution. Bed-parallel, calcite-filled fractures are common in shale. Knowing the aperture-size scaling and spatial organization of bed-parallel fractures may contribute to improved modeling of the combined fracture network (hydraulic and natural). Ten fracture data sets were collected from the Vaca Muerta (7), Marcellus (2) and Wolfcamp (1) shale formations. Bed-parallel fracture attributes such as strike, dip, aperture size, spacing, length and texture were collected from outcrops of the Vaca Muerta Formation in the Neuquén Basin, Argentina. Further fracture aperture-size and spacing data for the Vaca Muerta, and for the Marcellus and Wolfcamp, were collected through measurement direct from cores, and from photographic panels of slabbed core. A total of 1093 fractures were measured along 10 scanlines of total combined length of 629m. The aperture size of bed-parallel fractures ranges over 4 orders of magnitude, from 15 µm to 87 mm. Nine out of ten datasets follow a negative exponential distribution. Fracture attributes such as intensity and size range are different in the 3 studied shales. Even within the same shale formation, fracture intensity and size range can be variable. Aperture size ranges of bed-parallel and vertical fractures in these shales are comparable as are fracture intensities for the Marcellus examples. Bed-parallel fractures, however, have higher intensities than vertical fractures in the Vaca Muerta examples. Spatial organization of bed-parallel fractures is investigated using a normalized two-point correlation technique that allows distinction between clustering, regular spacing and a random distribution. The relationship between fracture spatial organization and stratigraphy and mechanical interfaces within the host rock is also investigated, with preliminary results suggesting that bed-parallel fractures are more intense in organic-rich layers in some cases, but not in others.Item Development of an efficient embedded discrete fracture model for 3D compositional reservoir simulation in fractured reservoirs(2013-08) Moinfar, Ali, 1984-; Sepehrnoori, Kamy, 1951-; Johns, Russell T.Naturally fractured reservoirs (NFRs) hold a significant amount of the world's hydrocarbon reserves. Compared to conventional reservoirs, NFRs exhibit a higher degree of heterogeneity and complexity created by fractures. The importance of fractures in production of oil and gas is not limited to naturally fractured reservoirs. The economic exploitation of unconventional reservoirs, which is increasingly a major source of short- and long-term energy in the United States, hinges in part on effective stimulation of low-permeability rock through multi-stage hydraulic fracturing of horizontal wells. Accurate modeling and simulation of fractured media is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make these methods inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent approaches for discrete fracture modeling may require large computational times and hence the oil industry has not widely used such approaches, even though they give more accurate representations of fractured reservoirs than dual continuum models. We developed an embedded discrete fracture model (EDFM) for an in-house fully-implicit compositional reservoir simulator. EDFM borrows the dual-medium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity and heterogeneity of a typical fractured reservoir. EDFM employs a structured grid to remediate challenges associated with unstructured gridding required for other discrete fracture models. Also, the EDFM approach can be easily incorporated in existing finite difference reservoir simulators. The accuracy of the EDFM approach was confirmed by comparing the results with analytical solutions and fine-grid, explicit-fracture simulations. Comparison of our results using the EDFM approach with fine-grid simulations showed that accurate results can be achieved using moderate grid refinements. This was further verified in a mesh sensitivity study that the EDFM approach with moderate grid refinement can obtain a converged solution. Hence, EDFM offers a computationally-efficient approach for simulating fluid flow in NFRs. Furthermore, several case studies presented in this study demonstrate the applicability, robustness, and efficiency of the EDFM approach for modeling fluid flow in fractured porous media. Another advantage of EDFM is its extensibility for various applications by incorporating different physics in the model. In order to examine the effect of pressure-dependent fracture properties on production, we incorporated the dynamic behavior of fractures into EDFM by employing empirical fracture deformation models. Our simulations showed that fracture deformation, caused by effective stress changes, substantially affects pressure depletion and hydrocarbon recovery. Based on the examples presented in this study, implementation of fracture geomechanical effects in EDFM did not degrade the computational performance of EDFM. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns suggested by microseismic data. We developed a coupled dual continuum and discrete fracture model to efficiently simulate production from these reservoirs. Large-scale hydraulic fractures were modeled explicitly using the EDFM approach and numerous small-scale natural fractures were modeled using a dual continuum approach. The transport parameters for dual continuum modeling of numerous natural fractures were derived by upscaling the EDFM equations. Comparison of the results using the coupled model with that of using the EDFM approach to represent all natural and hydraulic fractures explicitly showed that reasonably accurate results can be obtained at much lower computational cost by using the coupled approach with moderate grid refinements.Item Development of effective medium models for quantification of elastic properties and modeling of velocity dispersion of saturated rocks(2015-12) Sayar, Paul Mikhaël; Torres-Verdín, Carlos; Daigle, Hugh; Spikes, Kyle T; Olson, Jon; Sepehrnoori, KamyElastic effective medium theory (EMT) relates to quantitative rock physics modeling that calculates macroscopic properties of a mixture by incorporating the individual elastic properties, the volume fractions, and the spatial arrangement of the constituents that make up the rock. Despite the valuable merits of effective medium models, these theories exhibit limitations that require further investigation. Common instances are the non-unique configurations of the rock’s elements that give rise to identical wave velocities and the limiting assumption that rocks are purely elastic materials. Consequently, direct applications of classical EMTs can yield inaccurate and non-unique estimates of rock fabric properties that directly affect the assessment of elastic properties. The primary purpose of this dissertation is to improve the reliability of rock physics models based on the use of effective medium theories. In the first part, a rock physics model is developed for reliable estimation of velocities and elastic properties for sandstone-shale laminated rocks that are assumed to be vertical transverse isotropic (VTI). The new model is concerned with the reproduction of typical geological features and petrophysical properties of such formations that exhibit complex rock fabric. Isotropic and anisotropic versions of the self-consistent approximation and the differential effective medium theory, and Backus average are invoked to compute the effective medium’s stiffness tensor. The rock is separated into volumes of sandstone (regarded as isotropic) and shale (regarded as VTI), which are treated separately to reliably reproduce the spatial arrangement of the individual components included in the rock. Shale volumes enclose penny-shaped cracks and clay platelets aligned in the horizontal direction. Total porosity is divided into percolating porosity, isolated pores, and aligned fractures. The new simulation method is implement in three wells in the Haynesville shale and the Barnett shale. Estimates of elastic properties are verified when calculated velocities and sonic logs are in agreement. All relative differences between simulated and measured velocities are below 5.4%. To reduce non-uniqueness, electrical resistivity is calculated with modified effective medium theories and a procedure to compute Stoneley velocity is combined with the rock physics model. A method is advanced to calculate stress distribution and fracture initiation pressure around potential wellbores drilled horizontally in VTI rocks from the stiffness tensor obtained with the improved rock physics model. Effects of degree of anisotropy and elastic properties on fracture initiation pressure are investigated to determine a criterion to locate optimal depths along a vertical well to place a horizontal well. In the second part of the dissertation, an effective medium model is developed for reproduction of four of the main mechanisms of dispersion and attenuation of acoustic waves in saturated rocks. Simple and practical alternatives are introduced for effective medium modeling that account for dispersion mechanisms due to fluid flow inside the pore space. Biot’s flow and squirt flow effects are simulated by the calculation of frequency-dependent equivalent bulk and shear moduli for the solid background of the rock. When equal to the static moduli of minerals that compose the matrix of a rock at low frequencies, dynamic moduli of the solid background become complex at high frequencies and their absolute value increases. Frequency-dependent solid moduli are used as elastic properties of the matrix material in which fluid-filled porous inclusions are then added with dynamic self-consistent approximations for replication of acoustic scattering phenomena due to stiff pores and cracks. Resulting elastic features of the saturated medium calculated with the frequency-dependent effective medium model display viscoelastic behavior. Velocity predictions are conducted on synthetic examples to investigate conditions where dynamic rock physics modeling is necessary to obtain accurate elastic properties.Item Enhanced oil recovery (EOR) in unconventional reservoirs(2021-12-08) Junira, Adi; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Daigle, Hugh; Javadpour, Farzam; Ganjdanesh, RezaRapid production decline is typical in oil production from unconventional reservoirs. Enhanced oil recovery (EOR) with gas in cyclical (huff-n-puff) injection mode is arguably the most feasible method to solve the problem of relatively low oil recovery in the low permeability reservoirs, as supported by wealth of evidences. Nonetheless, the results so far seem vary widely. In some cases, the results are encouraging, while in some others, they are marginal. There seems to be many parameters to be considered in predicting the chance of a huff-n-puff gas EOR success. It is of interest not to just be able to forecast whether a huff-n-puff gas EOR will result in a satisfactory result, but also to obtain the highest oil recovery achievable, at least theoretically. With reliable real field data, rather than the synthetic one, research to identify the most significant factors affecting the gas EOR results in unconventional reservoirs by means of the widely used numerical simulation, is possible. The origin of the data should arguably give more credibility to the results, and thus their related analyses. Once the significant factors are identified and how they interact is understood, an optimum operational parameters design that maximizes the oil recovery is attainable. The acquired knowledge can also be of use in reducing the unknowns in other attempts with other methods to improve unconventional reservoirs’ oil recovery, so that the focus can be directed towards the right direction. Admittedly, uncertainties are inherent to the procedures used, but they are assumed to be acceptable for the purpose. This research found that the maximization of the oil recovery from unconventional reservoirs is viable and it is worth the resources spent. There seems to be some kind of matrix permeability threshold, below which the gas EOR will return meager even negative incremental oil recovery. This is because in order for the EOR to work well, the oil phase must be able to traverse with reasonable ease in the matrix, unless the injection gas effectively vaporizes the reservoir oil phase. Good injection gas choices are the ones that lower the oil viscosity while monotonically vaporize it in reservoir conditions. Field gas, [CO₂, C₂, C₃, and C₄] are usually good injection gas choices, with certain conditions. Single oil or gas phase in reservoir conditions is desirable, as the presence of another phase will adversely affect the phase flow, as described by the relative permeability curves concept. Good operational parameters are the ones that facilitate the production of the heavy components the most, while minimizing the obstruction to the oil influx from the matrix to the SRV. By extension, it is suggested that the use of water-based surfactant could be detrimental to the oil recovery in the long term, as the water phase will block the injection gas contact with the reservoir fluid. The inability to apply sufficiently high pressure without adversely affecting the aforementioned oil influx is a concerning challenge in the real field EOR implementation. Unless the reservoir permeability is enough to allow adequate oil phase mobility, it may be more reasonable to produce such unconventional reservoirs in primary production mode. Moreover, a higher GOR tends return a higher incremental oil recovery for black and volatile oil, in case of the EOR is applied from the beginning without a preceding primary production period. The data obtained from the oil-producing fields is also used to develop some kind of screening criteria for injection gas type, within which a huff-n-puff gas EOR will result in a good incremental oil recovery. The criteria cover the reservoir pressure, oil viscosity, C₇₊ molar fraction, and fracture conductivity. However, due to the available data is for reservoir oil with relatively low viscosity, the screening criteria is also more appropriate for such type of reservoir oil. As for the reservoir permeability point of view, the screening criteria is more suited for unconventional reservoirs with permeability of 685 nanodarcy or higherItem Fracture abundance and strain in folded cardium formation, Alberta fold-and-thrust belt, Canada(2014-12) Ozkul, Canalp; Eichhubl, Peter; Ukar, Estibalitz, 1980-The folded and thrusted Mesozoic clastic sequence of the Canadian Rocky Mountain foothills forms important hydrocarbon reservoirs. Understanding the distribution of natural fractures, their evolution, and timing of formation relative to the evolution of the fold-and-thrust system could potentially improve exploration and development outcomes in these otherwise tight unconventional reservoirs. However, the formation of fractures and their timing relative to folding and thrusting have remained unclear. I investigated the relation between folding and fracture formation in the Upper Cretaceous Cardium Sandstone by combining field structural observations and kinematic modeling of the fold-and-thrust belt evolution. I explored the relationship between fracture intensity and fracture strain with structural position by analyzing fracture spacing or frequency and aperture data collected along outcrop and micro-scanlines in the backlimb, in the forelimb close to the crest, and in the steeper dipping forelimb away from the crest of the Red Deer River anticline. Fracture frequency and aperture data collected both at the outcrop and micro scales indicate that variation in fracture strain is small across these three structural domains of the fold, with somewhat lower fracture intensity in the forelimb close to the crest. These fracture strain measurements are qualitatively consistent with calculated horizontal strain in the tectonic transport direction obtained through kinematic numerical models that simulate fold development associated with slip along the underlying Burnt Timber thrust. The models predict roughly similar amount of horizontal extension in both the back and forelimbs, and somewhat lower extension in the upper forelimb during early development of the Red Deer River anticline. Fracture formation early during fold development is consistent with the field structural observations of shear reactivation during later stages of folding. This combined kinematic modeling and field structural study demonstrates that deforming fold and thrust belts can undergo a complex evolution of bed-parallel extension in both space and time, resulting in spatially variable fracture formation in such structurally complex subsurface reservoirs.Item Identification of productive zones in unconventional reservoirs(2015-08) Tandon, Saurabh; McClure, Mark WilliamLarge-scale multi-stage fracture treatments in long horizontal wells have enabled economic hydrocarbon production from source mudrocks. A productive zone in mudrocks is defined as a region with high production or high productive potential. Rock fracability is an important parameter used in evaluating the productive potential in a source mudrocks. The fracability of the rock is the degree to which hydraulic fracturing can create a dense and conductive fracture network upon fracturing in the formation. However, there is no agreement on the formation geomechanical properties that result in a source rock having good fracability. The objective of this thesis to identify formation properties that may be related to fracability and to identify how these properties may be assessed from well logs. Once the properties have been identified, data from 15 wells in the Barnett shale are used to assess the effect of the properties on long-term production. We performed a sensitivity study on the effect of formation properties on the size of the stimulated rock volume. Field-scale simulations of a single fracturing stage were performed with CFRAC (Complex Fracturing ReseArch Code), a fracture simulator that couples fluid flow and stresses induced by fracture deformation (sliding and opening) in large, discrete fracture networks. Two-hundred simulations were performed with a uniform space filling design: a low discrepancy quasi-random sequence uniformly filling the hyper-parameter space. Each simulation used a different stochastically generated natural fracture network even though each was statistically similar in terms of fracture orientation, density, and length. Simulation results were post-processed to estimate a measure of the stimulated reservoir volume in each simulation. Parameters affecting tendency for shear stimulation fracture conductivity had the biggest effect on the stimulated reservoir volume. Unfortunately, these parameters are not easy to estimate in-situ. A review of the literature was carried out to understand the relationship between unpropped fracture conductivity (which cannot easily be measured in-situ) and other formation properties that could be quantified with available techniques. We used the concept of shear dilation angle to describe increase in conductivity in response to sliding. The dilation angle can be correlated to the joint compressive strength of the rock which is equal to the unconfined compressive strength for an unaltered rock. Unconfined compressive strength can be estimated from sonic logs. This hypothesis was tested on 15 wells in the Barnett Shale. Hydrocarbon-bearing zones were identified in the wells using the gamma ray log and the cumulative mechanical properties of the zones were compared to the long-term production of the wells. Results show that including the unconfined compressive strength in finding productive zones will improve the effectiveness of prediction models. Such a behavior alludes to the possibility that properties affecting unpropped fracture conductivity should be given consideration while planning and implementing fracture treatments in unconventional plays.Item Modeling interwell fracture interference and Huff-n-Puff pressure containment in Eagle Ford using EDFM(2019-06-26) Fiallos Torres, Mauricio Xavier; Sepehrnoori, Kamy, 1951-; Yu, WeiShale field operators have vested a tremendous interest in optimal spacing of infill wells and further fracture optimization, which ideally should have as little interference with the existing wells as possible. Although proper modeling has been employed to show the existence of well interference, few models have forecasted the impact of multiple inter-well fractures on child wells production and also implemented Huff-n-Puff and injection containment methods. These prognoses of the reservoir simulations abet to optimize further hydraulic fracture designs and improve the efficiency of Enhanced Oil Recovery (EOR) in unconventional reservoirs. This thesis presented a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of inter-well interference when modeling EOR Huff-n-Puff. Furthermore, we applied a non-intrusive embedded discrete fracture modeling (EDFM) method in conjunction with a commercial reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching, to propose profitable opportunities for Huff-n-Puff application. In this sense, the value of our workflow relies on a robust understanding of fracture properties, real production data validation, and the add-on feature of multi-pad wellbore image logging interpretation in the process. First, according to updated production data from Eagle Ford, the model was constructed to perform four (parent) wells history matching including five inner (child) wells. Later, fracture diagnostic results from well image logging were employed to perform sensitivity analysis on properties of long interwell connecting fractures such as number, conductivity, geometry, and explore their impacts on history matching. However, the estimation of these inter-well connecting fractures which were employed for enhanced history matching varied significantly from unmeasured fracture sensitivities. Finally, optimal cluster spacing was recommended considering interwell interference. The obtained results lead our study to the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthen the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies when EOR Huff-n-Puff is implemented. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation from image logs through the child wells in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest, considering more than 2000 hydraulic fractures. The model became a valuable stencil to inform the impacts on well location and spacing, the completion staging, initial huff-n-puff decisions, and subsequent containment strategies (e.g. to improve cycle timing and efficiency), so that it can be expanded to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support significant reductions in offset fracture interference by up to 50% and reduce completion costs up to 23% while improving new well capital efficiency. Consequently, these outcomes support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiencyItem Numerical modeling of complex hydraulic fracture development in unconventional reservoirs(2014-12) Wu, Kan; Olson, Jon E.; Balhoff, Matthew T.Successful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis.Item Seismic anisotropy analysis with Muir-Dellinger parameters(2017-05-03) Sripanich, Yanadet; Fomel, Sergey B; Fowler, Paul; Sen, Mrinal; Spikes, Kyle; Torres-Verdin, CarlosSeismic anisotropy, defined as the dependency of seismic-wave velocities on propagation direction, is an important factor in seismic data analysis. Neglecting anisotropy can lead to significant errors in the subsurface images. Even after decades of considerable research efforts, the topic of anisotropy remains at the center of attention of the research community. In this dissertation, I address the fundamental problem of choosing parameterization to characterize the effects of seismic anisotropy and propose an alternative approach based on the Muir-Dellinger (MD) parameters. I first give their definitions and discuss their properties with respect to the classic qP-wave phase velocity in transversely isotropic (TI) media in the second chapter. I show that, when expressed in terms of MD parameters, the exact expression of phase velocity in this case is controlled by the elliptical background and two anelliptic parameters (q1 and q3) defined as the curvature of the qP-wave phase velocity measured along the symmetry axis and its orthogonal. The wide range of possible values for the vertical shear-wave velocity (vS0) expressed under the conventional Thomsen parameterization translates to a considerably narrower range of the slope in the nearly linear dependence between q1 and q3. This discovery suggests a possibility of using such a relationship to characterize the complete stiffness tensor, infer more information about the subsurface directly from qP kinematics, and provide a physical basis for reducing the number of parameters in qP-wave analysis. Based on various experimental measurements of stiffness coefficients reported in the literature, I relate such properties in shales, sandstones, and carbonates with corresponding values of slope. I further investigate this empirical linear relationship in the third chapter and show that it can also gives additional rock physics implications about the type of pore fluids. I provide some supportive evidence of its reality from self-consistent rock physics modeling and Backus averaging for shale samples. In addition, I find that both the 2D MD parameterization and its 3D extension, suitable for studies of qP waves in orthorhombic media, also provide a convenient foundation for the parameter estimation process. I carry out a detailed study on the sensitivity of MD parameters to qP-wave kinematics in comparison with other known anisotropic parameterization schemes in the fourth chapter. In the last chapter, using the MD parameters, I propose novel analytical approximations for qP-wave phase and group velocities in 2D TI and 3D orthorhombic media. The novel approximations are highly accurate and possess an advantage of having similar functional form with reciprocal coefficients, which adds practical convenience to considering both phase (wave) and group (ray) velocities. Finally, I discuss known limitations of the MD parameterization and suggest possible future research topics.Item Simple mechanistic modeling of recovery from unconventional oil reservoirs(2015-05) Ogunyomi, Babafemi Anthony; Lake, Larry W.; Sepehrnoori, Kamy; Srinivasan, Sanjay; Jablonowski, Christopher J.; Bickel, James E.Decline curve analysis is the most widely used method of performance forecasting in the petroleum industry. However, when these techniques are applied to production data from unconventional reservoirs they yield model parameters that result in infinite (nonphysical) values of reserves. Because these methods were empirically derived the model parameters are not functions of reservoir/well properties. Therefore detailed numerical flow simulation is usually required to obtain accurate rate and expected ultimate recovery (EUR) forecast. But this approach is time consuming and the inputs in to the simulator are highly uncertain. This renders it impractical for use in integrated asset models or field development optimization studies. The main objective of this study is to develop new and “simple” models to mitigate some of these limitations. To achieve this object field production data from an unconventional oil reservoir was carefully analyzed to identify flow regimes and understand the overall decline behavior. Using the result from this analysis we use design of experiment (DoE), numerical reservoir simulation and multivariate regression analysis to develop a workflow to correlate empirical model parameters and reservoir/well properties. Another result from this analysis showed that there are at least two time scales in the production data (existing empirical and analytical model do not account for this fact). Double porosity models that account for the multiple time scales only have complete solutions in Laplace space and this make them difficult to use in optimization studies. A new approximate analytical solution to the double porosity model was developed and validated with synthetic data. It was shown that the model parameters are functions of reservoir/well properties. In addition, a new analytical model was developed based on the parallel flow conceptual model. A new method is also presented to predict the performance of fractured wells with complex fracture geometries that combines a fundamental solution to the diffusivity equation and line/surface/volume integral to develop solutions for complex fracture geometries. We also present new early and late time solutions to the double porosity model that provide explicit functions for skin and well/fracture storage, which can be used to improve the characterization of fractured horizontal wells from early-time production data.Item Simulations of fluid invasion during fracturing in unconventional reservoirs(2020-11-30) Pérez Hernández, Rafael Eduardo; DiCarlo, David Anthony, 1969-Unconventional reservoirs have become relevant as a new source of hydrocarbon reserves over the last years. The application hydraulic fracturing is needed to grant hydrocarbon production due to unconventional rocks lack of permeability. The fluids used in the fracturing leak-off into the rock matrix affecting potentially fracture geometry, and hydrocarbon production. Consequently, the understanding of fluid leak-off at laboratory and field scale is a key factor to choose the most suitable stimulation fluid. This work is divided in two parts: The first section is related to the simulation of the laboratory leak-off test behavior. The second section analyses reservoir fluid invasion phenomena, and the validation of previously proposed general leak-off model. The first part of the thesis presents the simulation of the laboratory invasion test performed by Luo (2020), determining the key rock-fluid parameters like porosity, permeability, fluid properties and flow models that suit this specific porous media problem on the simulator. The simulation matching was performed over three different invasion cases: water, gas, and foam invasion (combination) using a 10 millidarcy core and considering two constant pressure boundary conditions at the injection and production sides. In the last part of the laboratory approach, the matched cases were run over permeability sensitivities to determined leak-off dependencies. Finally, the simulation results show a differing dependency for water (κ [superscript 0.75]), and gas cases (κ [superscript 1.25]), both diverging from the general leak off model statements (κ [superscript 0.5]). The second part shows the leak-off reservoir approach, where the simulation parameters were set to mimic reservoir conditions. Three different invasion process were simulated in a 100 nanodarcy core including: gas invasion, water invasion, and foam invasion (combination). The results matched the expected square root of time behavior for all fluids stated in general leak-off model, differing from the linear behavior seen in the core gas invasion simulations. Moreover, several sensitivities were performed to understand the dependencies related to permeability, delta pressure, gas viscosity and oil compressibility, refuting the expected reservoir behavior explored in the general leak-off model. Finally, the sensitivities allow the determination of new corroborated proportionalities and suggested a more accurate model over the established reservoir conditionsItem Uncertainty quantification of unconventional reservoirs using assisted history matching methods(2019-09-17) Eltahan, Esmail Mohamed Khalil; Sepehrnoori, Kamy, 1951-A hallmark of unconventional reservoirs is characterization uncertainty. Assisted History Matching (AHM) methods provide attractive means for uncertainty quantification (UQ), because they yield an ensemble of qualifying models instead of a single candidate. Here we integrate embedded discrete fracture model (EDFM), one of fractured-reservoirs modeling techniques, with a commercial AHM and optimization tool. We develop a new parameterization scheme that allows for altering individual properties of multiple wells or fracture groups. The reservoir is divided into three types of regions: formation matrix; EDFM fracture groups; and stimulated rock volume (SRV) around fracture groups. The method is developed in a sleek, stand-alone form and is composed of four main steps: (1) reading parameters exported by tool; (2) generating an EDFM instance; (3) running the instance on a simulator; and (4) calculating a pre-defined objective function. We present two applications. First, we test the method on a hypothetical case with synthetic production data from two wells. Using 20 history-matching parameters, we compare the performance of five AHM algorithms. Two of which are based on Bayesian approach, two are stochastic particle-swarm optimization (PSO), and one is commercial DECE algorithm. Performance is measured with metrics, such as solutions sample size, total simulation runs, marginal parameter posterior distributions, and distributions of estimated ultimate recovery (EUR). In the second application, we assess the effect of natural fractures on UQ of a single horizontal well in the middle Bakken. This is achieved by comparing four AHM scenarios with increasingly varying natural-fracture intensity. Results of the first study show that, based on pre-set acceptance criteria, DECE fails to generate any satisfying solutions. Bayesian methods are noticeably superior to PSO, although PSO is capable to generate large number of solutions. PSO tends to be focused on narrow regions of the posteriors and seems to significantly underestimate uncertainty. Bayesian Algorithm I, a method with a proxy-based acceptance/rejection sampler, ranks first in efficiency but evidently underperforms in accuracy. Results from the second study reveal that, even though varying intensity of natural fractures cam significantly alter other model parameters, that appears not to have influence on UQ (or long-term production)