Browsing by Subject "shale"
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Item A Study of Hydraulic Fracturing Initiation in Transversely Isotropic Rocks(2011-10-21) Serajian, VahidHydraulic fracturing of transverse isotropic reservoirs is of major interest for reservoir stimulation and in-situ stress estimation. Rock fabric anisotropy not only causes in-situ stress anisotropy, but also affects fracture initiation from the wellbore. In this study a semi-analytical method is used to investigate these effects with particular reference to shale stimulation. Using simplifying assumptions, equations are derived for stress distribution around the wellbore's walls. The model is then used to study the fracture initiation pressure variations with anisotropy. A sensitivity analysis is carried out on the impact of Young's modulus and Poisson's ration, on the fracture initiation pressure. The results are useful in designing hydraulic fractures and also can be used to develop information about in-situ rock properties using failure pressure values observed in the field. Finally, mechanical and permeability anisotropy are measured using Pulse Permeameter and triaxial tests on Pierre shale.Item Comparison of Various Deterministic Forecasting Techniques in Shale Gas Reservoirs with Emphasis on the Duong Method(2012-10-19) Joshi, Krunal JaykantThere is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many methods including volumetric, Decline Curve Analysis (DCA), analytical simulation and numerical simulation. Each one of these methods has its advantages and disadvantages, but only the DCA technique can use readily available production data to forecast rapidly and to an extent accurately. The DCA methods in use in the industry such as the Arps method had originally been developed for Boundary dominated flow (BDF) wells but it has been observed in shale reservoirs the predominant flow regime is transient flow. Therefore it was imperative to develop newer models to match and forecast transient flow regimes. The SEDM/SEPD, the Duong model and the Arps with a minimum decline rate are models that have the ability to match and forecast wells with transient flow followed by boundary flow. I have revised the Duong model to forecast better than the original model. I have also observed a certain variation of the Duong model proves to be a robust model for most of the well cases and flow regimes. The modified Duong has been shown to work best compared to other deterministic models in most cases. For grouped datasets the SPED & Duong models forecast accurately while the Modified Arps does a poor job.Item New Advances in Shale Gas Reservoir Analysis Using Water Flowback Data(2014-04-04) Alkouh, AhmadShale gas reservoirs with multistage hydraulic fractures are commonly characterized by analyzing long-term gas production data, but water flowback data is usually not included in the analysis. However, this work shows there can be benefits to including post-frac water flowback and long-term water production data in well analysis. In addition, field data indicate that only 10-40% of the frac water is recovered after the flowback. This work addresses two main question: Where is the rest of the injected frac fluid that is not recovered and what is the mechanism that is trapping it? And how can the water flowback data be used in estimating effective fracture volume using production data analysis tools? A number of simulation cases were run for single and two phase (gas/water) for modeling flowback and long-term production periods. Various physical assumptions were investigated for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. The results of these simulations were compared with analytical solutions and data from actual wells using diagnostic and specialized plots. The results of these comparisons led to certain conclusions and procedures describing possible reservoir conditions after hydraulic fracturing and during production. Past publications have suggested that the lost frac water is trapped in the natural fracture or imbibed into the rock matrix near the fracture face. Natural fracture spacing could be a possible explanation of the lost frac water. These concepts are tested and the challenge of simulating a natural fracture with trapped water without imbibition is solved using a new hybrid relative permeability jail. This concept was tested for the period of flowback, shut-in and production. This work presents the benefits of a new method for combining water flowback and long-term water production data in shale gas analysis. Water production analysis can provide effective fracture volume which was confirmed by the cumulative produced water. This will help when evaluating fracture-stimulation jobs. It also shows the benefits of combining flowback and long-term water production data in the analysis of shale gas wells. In some cases, the time shift on diagnostic plots changes the apparent flow regime identification of early gas production data. This leads to different models of the fracture/matrix system. The presented work shows the importance of collecting and including water flowback data in long-term production data.Item Paleoenvrironmental Controls on Diagenesis of Organich-Rich Shales in the Eagle Ford Group(2014-08-27) Kruse, KendraCarbonate precipitation can be either promoted or inhibited by microbial processes in different redox zones. It is therefore possible for basin redox evolution to indirectly control early carbonate diagenesis and modify reservoir properties of corresponding shale units. The goals of this study were to analyze geochemical characteristics of the Late Cretaceous Eagle Ford Group in McMullen County, Texas to test the hypotheses that (1) the redox state of the water column controlled carbonate cement abundance and (2) carbonate cement lowered organic matter content by volumetric dilution. An x-ray analytical microscope was used to map elemental compositions of fresh core samples within the Eagle Ford Group. Resultant maps were used to characterize carbonate cements and to estimate the redox state of the overlying water column during deposition, as indicated by the relative abundances of the trace metals Mo, V, and Cr. Results indicate that cementation occurred early relative to compaction. Ti Kal normalized Mo Kal and CaKal fluorescence intensities are positively correlated throughout the unit, suggesting that carbonate cementation was related to the redox state. Total organic carbon is negatively correlated in the upper Lower Eagle Ford with (Ca Kal)/(Ti Kal) fluorescence ratio, consistent with volumetric dilution of organic matter by diagenetic cementation prior to compaction. In contrast, there is no significant correlation between total organic carbon and carbonate content in the more organic-rich Lower Eagle Ford.Item Permeability Estimation from Fracture Calibration Test Analysis in Shale and Tight Gas(2012-12-13) Xue, Han 1988-Permeability estimation in tight and shale reservoirs is challenging because little or no flow will occur without hydraulic fracture stimulation. In the pressure falloff following a fracture calibration test (FCT), radial flow after the fracture closure can be used to estimate the reservoir permeability. However, for very low permeability, the time to reach radial flow can exceed any practical duration. This study shows how to use the reservoir pressure to estimate the maximum reservoir permeability when radial flow is missing in the after-closure response. The approach is straightforward and can also be used for buildup tests. It applies whenever the well completion geometry permits radial flow before the pressure response encounters a real well drainage limits. Recent developments have blurred the boundary between fracture calibration test analysis and classic pressure transient analysis. Adapting the log-log diagnostic plot representation to the FCT analysis has made it possible to perform before and after closure analysis on the same diagnostic plot. This paper also proposes a method for diagnosing abnormal leakoff behavior using the log-log diagnostic plot as an alternative method for the traditional G-function plot. The results show the relationship between reservoir permeability and pressure can be used effectively for both estimation of the permeability upper bound when there is no apparent radial flow and for confirming the permeability estimated from apparent late time radial flow. Numerous field examples illustrate this simple and powerful insight.Item Rock Physics Characterization of Organic-Rich Shale Formations to Predict Organic Properties(2013-07-29) Bush, BrandonHydrocarbon production from organic-rich shale formations has significantly increased since the advent of sophisticated recovery techniques which allow for economical production from such formations. The primary formation properties that operators rely on to assess the economic potential of these formations are: total organic carbon (TOC), thermal maturity, hydrocarbon saturation, porosity, mineralogy and brittleness. In this thesis, I investigate rock physics models and methods for the possible estimation of these formation properties of organic-rich shale formations from and well log and seismic data. The rock physics model applied in this research integrates Gassmann and Sun models to predict the elastic properties of organic-rich shale formations. Sun?s model utilizes a pore-structure parameter (PSP) which relates to the rigidity and pore structure of the rock. The rock physics model is separated into two stages based on the identification that organic-rich shale contains both organic and inorganic porosity. Organic porosity contains hydrocarbon while inorganic porosity contains water; organic porosity and associated hydrocarbon are created during the maturation of solid organic matter. The first stage of the model incorporates the organic matter into the structural matrix of the rock; the second stage then introduces the current total porosity into the total rock matrix. The ideal case, studied in this paper, assumes that all porosity is organic porosity; the parameters for each stage in the ideal case would be related and potentially approximate to each other, simplifying the resulting nonlinear model. The modeled PSP is observed to correlate with rock properties, specifically the TOC, hydrocarbon saturation, thermal maturity, clay volume and acoustic impedance. Significant variation still occurs between the PSP and some rock properties, this suggests the actual case is much more complicated than the ideal situation. A strong correlation between the PSP and organic properties is seen as the amount of organic material increases suggesting that higher amounts of variation with lower organic content relates to intervals where the ideal case is not valid; the correlation is greater with respect to the shear wave, indicating the importance of the shear wave to rock physics modeling. Through the integration of Gassmann and Sun equations a rock physics model has been developed which can potentially relate organic-rock properties to acoustic properties, this correlation can greatly enhance the evaluation of organic-rich shale play development from log analysis and possibly seismic inversion.Item Study of Flow Regimes in Multiply-Fractured Horizontal Wells in Tight Gas and Shale Gas Reservoir Systems(2010-07-14) Freeman, Craig M.Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a small number of analytical models and published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems. The purpose of this work is to construct a fit-for-purpose numerical simulator which will account for a variety of production features pertinent to these systems, and to use this model to study the effects of various parameters on flow behavior. Specific features examined in this work include hydraulically fractured horizontal wells, multiple porosity and permeability fields, desorption, and micro-scale flow effects. The theoretical basis of the model is described in Chapter I, along with a validation of the model. We employ the numerical simulator to examine various tight gas and shale gas systems and to illustrate and define the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as high-resolution maps of pressure distributions. The results of this study are described in Chapter II. We use pressure maps to illustrate the initial linear flow into the hydraulic fractures in a tight gas system, transitioning to compound formation linear flow, and then into elliptical flow. We show that flow behavior is dominated by the fracture configuration due to the extremely low permeability of shale. We also explore the possible effect of microscale flow effects on gas effective permeability and subsequent gas species fractionation. We examine the interaction of sorptive diffusion and Knudsen diffusion. We show that microscale porous media can result in a compositional shift in produced gas concentration without the presence of adsorbed gas. The development and implementation of the micro-flow model is documented in Chapter III. This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.Item Study of Multi-scale Transport Phenomena in Tight Gas and Shale Gas Reservoir Systems(2013-11-25) Freeman, Craig MatthewThe hydrocarbon resources found in shale reservoirs have become an important energy source in recent years. Unconventional geological and engineering features of shale systems pose challenges to the characterization of these systems. These challenges have impeded efficient economic development of shale resources. New fundamental insights and tools are needed to improve the state of shale gas development. Few attempts have been made to model the compositional behavior of fluids in shale gas reservoirs. The transport and storage of reservoir fluids in shale is controlled by multiple distinct micro-scale physical phenomena. These phenomena include preferential Knudsen diffusion, differential desorption, and capillary critical effects. Together, these phenomena cause significant changes in fluid composition in the subsurface and a measureable change in the composition of the produced gas over time. In order to quantify this compositional change we developed a numerical model describing the coupled processes of desorption, diffusion, and phase behavior in heterogeneous ultra-tight rocks as a function of pore size. The model captures the various configurations of fractures induced by shale gas fracture stimulation. Through modeling of the physics at the macro-scale (e.g. reservoir-scale hydraulic fractures) and micro-scale (e.g. Knudsen diffusion in kerogen nanopores), we illustrate how and why gas composition changes spatially and temporally during production. We compare the results of our numerical model against measured composition data obtained at regular intervals from shale gas wells. We utilize the characteristic behaviors explicated by the model results to identify features in the measured data. We present a basis for a new method of production data analysis incorporating gas composition measurements in order to develop a more complete diagnostic process. Distinct fluctuations in the flowing gas composition are shown to uniquely identify the onset of fracture interference in horizontal wells with multiple transverse hydraulic fractures. The timescale and durations of the transitional flow regimes in shales are quantified using these measured composition data. These assessments appear to be robust even for high levels of noise in the rate and pressure data. Integration of the compositional shift analysis of this work with modern production analysis is used to infer reservoir properties. This work extends the current understanding of flow behavior and well performance for shale gas systems to encompass the physical phenomena leading to compositional change. This new understanding may be used to aid well performance analysis, optimize fracture and completion design, and improve the accuracy of reserves estimates. In this work we contribute a numerical model which captures multicomponent desorption, diffusion, and phase behavior in ultra-tight rocks. We also describe a workflow for incorporating measured gas composition data into modern production analysis.Item The Effect of Proppant Size and Concentration on Hydraulic Fracture Conductivity in Shale Reservoirs(2013-04-11) Kamenov, AntonHydraulic fracture conductivity in ultra-low permeability shale reservoirs is directly related to well productivity. The main goal of hydraulic fracturing in shale formations is to create a network of conductive pathways in the rock which increase the surface area of the formation that is connected to the wellbore. These highly conductive fractures significantly increase the production rates of petroleum fluids. During the process of hydraulic fracturing proppant is pumped and distributed in the fractures to keep them open after closure. Economic considerations have driven the industry to find ways to determine the optimal type, size and concentration of proppant that would enhance fracture conductivity and improve well performance. Therefore, direct laboratory conductivity measurements using real shale samples under realistic experimental conditions are needed for reliable hydraulic fracturing design optimization. A series of laboratory experiments was conducted to measure the conductivity of propped and unpropped fractures of Barnett shale using a modified API conductivity cell at room temperature for both natural fractures and induced fractures. The induced fractures were artificially created along the bedding plane to account for the effect of fracture face roughness on conductivity. The cementing material present on the surface of the natural fractures was preserved only for the initial unpropped conductivity tests. Natural proppants of difference sizes were manually placed and evenly distributed along the fracture face. The effect of proppant monolayer was also studied.