Browsing by Subject "hydraulic fracturing"
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Item Characterization of Filter Cake Buildup and Cleanup under Dynamic Fluid Loss Conditions(2011-10-21) Yango, TakweHydraulic fracturing is a popular stimulation method in tight gas and shale gas reservoirs that uses a viscous fluid to fracture the reservoir rock and uniformly transport proppant to create a highly conductive path that is kept open by the proppant after fracturing. This method is used to improve the productivity of the otherwise low permeability reservoirs. Hydraulic fracturing, though in general beneficial, is a complex process that has a number of challenges in fracturing design and execution. This research focuses on studying the damage caused by the fracturing fluid (gel) to the fracture and the conditions to remove the damage. Guar gum and its derivatives have been the most commonly used polymers to increase the viscosity of fracturing fluids. The fracturing fluid gets dehydrated under pressure leaving behind a highly concentrated unbroken residue called filter cake which causes permeability impairment in the proppant pack, resulting in low fracture conductivity and decreased effective fracture length. This study seeks to characterize filter cakes. By measuring its thickness and with the leak off volume, the concentration and yield stress of the filter cake can be estimated. The thickness of the filter cake was measured with a precise laser profilometer. Correlations are proposed to estimate filter cake properties (thickness, concentration and yield stress) based on pumping conditions (pump rate, time and net pressure) and rock properties. With these properties known, a required flow back rate of the reservoir fluid can be estimated to clean up the filter cake modeled as a non-newtonian fluid exhibiting a yield stress. Typical field conditions were referenced and scaled down in the lab to closely represent the field conditions. Recommendations are provided on gel damage based on the observation of the study.Item Dynamic Fracture Conductivity?An Experimental Investigation Based on Factorial Analysis(2013-01-31) Awoleke, Obadare OThis work is about fracture conductivity; how to measure and model it based on experimental data. It is also about how to determine the relative importance of the factors that affect its magnitude and how to predict its magnitude based on these factors. We dynamically placed the slurry hereby simulating the slurry placement procedure in a field-scale fracture. We also used factorial and fractional factorial designs as the basis of our experimental investigation. The analysis and interpretation of experimental results take into account the stochastic nature of the process. We found that the relative importance of the investigated factors is dependent on the presence of outliers and how they are handled. Based on our investigation we concluded that the investigated factors arranged in order of decreasing impact on conductivity are: closure stress, polymer loading, flow back rate, presence of breaker, temperature and proppant concentration. In particular, we find that at high temperatures, fracture conductivity was severely reduced due to the formation of a dense proppant-polymer cake. Also, dehydration of the residual gel in the fracture at high flow back rates appears to cause severe damage to conductivity at higher temperatures. This represents a new way of thinking about the fracture cleanup process; not only as a displacement process, but also as a displacement and evaporative process. In engineering practice, this implies that aggressive flow back schemes are not necessarily beneficial for conductivity development. Also, we find that at low proppant concentrations, there is the increased likelihood of the formation of channels and high porosity fractures resulting in high fracture conductivities. The uniqueness of this work is a focus on the development of a conductivity model using regression analysis and also the illustration of a procedure that can be used to develop a conductivity model using dimensional analysis. We reviewed both methodologies and applied them to the challenge of modeling fracture conductivity from experimental studies.Item Gas Deliverability Using the Method of Distributed Volumetric Sources(2010-01-15) Jin, XiaozeProductivity index (PI) is an important indicator of a well?s production capacity. For conventional reservoirs, well productivity is usually calculated using the pressure response of the reservoir in its pseudosteady-state period. There are numerous studies for different well completion schemes which developed correlations for pseudosteady-state productivity index for specific cases, such as horizontal wells and fractured wells. Most of the developed models for complex well completion schemes use some approximations for productivity index calculation and they have some limitations in use. Furthermore, as the petroleum industry goes toward producing lower quality reservoirs like low- and ultra low-permeability reservoirs, the period of transient flow covers a larger part of the well lifetime and these pseudosteady-state productivity calculations become less applicable in prediction of the reservoir?s production behavior. The Distributed Volumetric Sources (DVS) method seems able to fill this gap. Our method is able to predict the productivity index of a general well completion scheme for transient as well as pseudosteady-state flow periods. In this study, we focus on a typical well completion scheme ? vertical well intersected by a vertical fracture of finite conductivity. Parametric study is performed by varying the proppant pack permeability with a linear distribution, varying fracture width with an elliptical distribution and varying fracture height with an elliptical distribution. The details of hydraulic fracture are integrated into the calculation of well productivity. By combining the well productivity with gas material balance, production forecasting of the hydraulically fractured wells could be easily obtained. The result of production forecasting could be used to aid in decision making of choosing the best stimulation treatment. Field examples are presented to illustrate the application of this technology for production modeling the complicated reservoir cases involving fracture stimulation.Item Incorporating Rigorous Height Determination into Unified Fracture Design(2010-10-12) Pitakbunkate, TermpanHydraulic fracturing plays an important role in increasing production rate in tight reservoirs. The performance of the reservoir after fracturing can be observed from the productivity index. This parameter is dependent on the fracture geometry; height, length and width. Unified fracture design (UFD) offers a method to determine the fracture dimensions providing the maximum productivity index for a specific proppant amount. Then, in order to achieve the maximum productivity index, the treatment schedules including the amount of liquid and proppant used for each stage must be determined according to the fracture dimensions obtained from the UFD. The proppant number is necessary for determining the fracture geometry using the UFD. This number is used to find the maximum productivity index for a given proppant amount. Then, the dimensionless fracture conductivity index corresponding to the maximum productivity index can be computed. The penetration ration, the fracture length, and the propped fracture width can be computed from the dimensionless fracture conductivity. However, calculating the proppant number used in UFD requires the fracture height as an input. The most convenient way to estimate fracture height to input to the UFD is to assume that the fracture height is restricted by stress contrast between the pay zone and over and under-lying layers. In other words, the fracture height is assumed to be constant, independent of net pressure and equal to the thickness of the layer which has the least minimum principal stress. However, in reality, the fracture may grow out from the target formation and the height of fracture is dependent on the net pressure during the treatment. Therefore, it is necessary to couple determination of the fracture height with determination of the other fracture parameters. In this research, equilibrium height theory is applied to rigorously determine the height of fracture. Solving the problem iteratively, it is possible to incorporate the rigorous fracture height determination into the unified fracture design.Item Modeling Performance of Horizontal Wells with Multiple Fractures in Tight Gas Reservoirs(2011-02-22) Dong, GuangweiMultiple transverse fracturing along a horizontal well is a relatively new technology that is designed to increase well productivity by increasing the contact between the reservoir and the wellbore. For multiple transverse fractures, the performance of the well system is determined by three aspects: the inflow from the reservoir to the fracture, the flow from the fracture to the wellbore, and the inflow from the reservoir to the horizontal wellbore. These three aspects influence each other and combined, influence the wellbore outflow. In this study, we develop a model to effectively formulate the inter-relationships of a multi-fracture system. This model includes a reservoir model and a wellbore model. The reservoir model is established to calculate both independent and inter-fracture productivity index to quantify the contribution from all fractures on pressure drop of each fracture, by using the source functions to solve the single-phase gas reservoir flow model. The wellbore model is used to calculate the pressure distribution along the wellbore and the relationship of pressure between neighboring fractures, based on the basic pressure drop model derived from the mechanical energy balance. A set of equations with exactly the same number of fractures will be formed to model the system by integrating the two models. Because the equations are nonlinear, iteration method is used to solve them. With our integrated reservoir and wellbore model, we conduct a field study to find the best strategy to develop the field by hydraulic fracturing. The influence of reservoir size, horizontal and vertical permeability, well placement, and fracture orientation, type (longitudinal and transverse), number and distribution are completely examined in this study. For any specific field, a rigorous step-by-step procedure is proposed to optimize the field.Item Optimal fracture treatment design for dry gas wells maximizes well performance in the presence of non-Darcy flow effects(Texas A&M University, 2004-11-15) Lopez Hernandez, Henry De JesusThis thesis presents a methodology based on Proppant Number approach for optimal fracture treatment design of natural gas wells considering non-Darcy flow effects in the design process. Closure stress is taken into account, by default, because it is the first factor decreasing propped pack permeability at in-situ conditions. Gel damage was also considered in order to evaluate the impact of incorporating more damaging factors on ultimate well performance and optimal geometry. Effective fracture permeability and optimal fracture geometry are calculated through an iterative process. This approach was implemented in a spreadsheet. Non-Darcy flow is described by the ? factor. All ? factor correlations available in the literature were evaluated. It is recommended to use the correlation developed specifically for the given type of proppant and mesh size, if available. Otherwise, the Pursell et al. or the Martins et al. equations are recommended as across the board reliable correlations for predicting non-Darcy flow effects in the propped pack. The proposed methodology was implemented in the design of 11 fracture treatments of 3 natural tight gas wells in South Texas. Results show that optimal fracture design might increase expected production in 9.64 MMscf with respect to design that assumes Darcy flow through the propped pack. The basic finding is that for a given amount of proppant shorter and wider fractures compensate the non-Darcy and/or gel damage effect. Dynamic programming technique was implemented in design of multistage fractures for one of the wells under study for maximizing total gas production. Results show it is a powerful and simple technique for this application. It is recommended to expand its use in multistage fracture designs.Item Rigorous Simulation Model of Kerogen Pyrolysis for the In-situ Upgrading of Oil Shales(2014-10-09) Lee, Kyung JaeOil shale is a vast, yet untapped energy source, and the pyrolysis of kerogen in the oil shales releases recoverable hydrocarbons. In this dissertation, we investigate how to increase process efficiency and decrease the costs of in-situ upgrading process for kerogen pyrolysis, which is applicable to the majority of the oil shales. In-situ upgrading processes include (a) Shell In-situ Conversion Process (ICP), (b) ExxonMobil Electrofrac, and (c) Texas A&M (TAMU) Steamfrac. We evaluate these three processes in realistic scenarios using our newly developed multi-phase, multi-component, nonisothermal simulator. Kerogen pyrolysis is represented by 6 kinetic reactions resulting in 10 components and 4 phases. Expanding TAMU Flow and Transport Simulator (FTSim), we develop a fully functional capability that describes the kerogen pyrolysis and the accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media, and accurately accounts for phase equilibria and transitions. It provides a powerful tool to evaluate the efficiency and the productivity of the in-situ upgrading processes. We validate our simulator by reproducing the field production data of the Shell ICP implemented in Green River Formation. We conduct the sensitivity analyses of the presence and absence of pre-existing fracture system, oil shale grade, permeability of the fracture network, and thermal conductivity of the formation. Validated model has the oil shale grade of 25 gal/ton, fracture domain permeability of 150 md, and formation thermal conductivity of 2.0 W/m-K. In the application cases, we analyze the significant factors affecting each process. In the Shell ICP, the ExxonMobil Electrofrac, and the TAMU Steamfrac, we study the effects of heater temperature, electrical conductivities of injection material, and steam injection strategy, respectively. We find that the best case of the Shell ICP showed the highest energy efficiency of 144 %. The best cases of the ExxonMobil Electrofrac and the TAMU Steamfrac show the energy efficiency of 74.1 %, and 54.1 %, respectively. We obtain positive Net Present Value (NPV) in the TAMU Steamfrac by much less number of wells than the Shell ICP and the ExxonMobil Electrofrac, though it has the lowest energy efficiency.Item Rock-Fluid Chemistry Impacts on Shale Hydraulic Fracture and Microfracture Growth(2012-07-16) Aderibigbe, AderonkeThe role of surface chemical effects in hydraulic fracturing of shale is studied using the results of unconfined compression tests and Brazilian tests on Mancos shale- cored at depths of 20-60 ft. The rock mineralogy, total organic carbon and cation exchange capacity were determined in order to characterize the shale. Adsorption tests to study the interaction of the shale and aqueous fluid mixture were also carried out using surface tension measurements. The uniaxial compressive strengths and tensile strengths of individual shale samples after four hours exposure to water, 2.85 x 10^-3 M cationic surfactant (dodecyltrimethylammonium bromide-DTAB) and 2.81 x 10^-3 M anionic surfactant (sodium dodecylbenzenesulfonate-SDBS) were analyzed using ANOVA and Bonferroni tests. These mechanical strengths were largely reduced on exposure to the aqueous environments studied, despite the relatively low clay and low swelling clay content of the Mancos shale. Further comparison of the uniaxial compressive strengths and tensile strengths of the shale on exposure to water, to the strengths when exposed to the surfactant solutions showed that their difference was not statistically significant indicating that exposure to water had the greatest effect on strength loss. The surface tension measurement of 2.85 x 10^-4 M DTAB and 2.81 x 10^-4 M SDBS solutions before and after equilibration with shale showed about 80% increase in surface tension in the DTAB solution and 10% increase in surface tension in the SDBS solution. The probable sorption mechanism is electrostatic attraction with negatively charged sites of the shale as shown by significant loss of the cationic surfactant (DTAB) to the shale surface, and the relatively minor adsorption capacity of the anionic surfactant (SDBS). Although these adsorption tests indicate interaction between the shale and surfactant solutions, within the number of tests carried out and the surfactant concentration used, the interaction does not translate into a significant statistical difference for impacts of surfactants on mechanical strength of this shale compared to the impact of water alone. The relevance of this work is to facilitate the understanding of how the strength of rock can be reduced by the composition of hydraulic fracturing fluids, to achieve improved fracture performance and higher recovery of natural gas from shale 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 Thickness Measurement of Fracture Fluid Gel Filter Cake after Static Build Up and Shear Erosion(2011-08-08) Xu, BenThe hydraulic fracturing treatment is an essential tight sand gas reservoir stimulation that employs viscous fluid to break the formation rock to create a fracture and transport the propping agent to support the fracture from naturally healing. Despite proven economic benefit, the hydraulic fracture fluid damages the producing formation and the propped fracture. To analyze the gel damage effect quantitatively, the filter cake thickness is used as a parameter that has not been measured before. This project was divided into two stages. The first stage built up a filter cake and measured the filter cake thickness by a laser profilometer. A correlation between leakoff volume and filter cake thickness was produced. The second stage eroded the filter cake by flowing original fracturing fluid through the core sample to study the fracturing fluid shear clean up effect on filter cake thickness. The filter cake was built up in the lab and the thickness was measured with different methods. The profilometer has been tested as an effective tool to measure the filter cake thickness. A correlation for crosslinked guar fracture fluid filter cake thickness was produced. An experiment setup used to shear erode the filter cake was built and tested. The results showed the filter cake was not eroded at 200 s-1 shear rate.