Browsing by Subject "tight gas"
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Item A New Analytical Method to Quantify Residual Fluid Cleanup in Hydraulic Fractures(2014-04-17) Zarrin, TahiraA number of factors contribute to reduce the production benefits from hydraulic fracturing, including inefficient fluid design, poor proppant selection and or, the inability of fracture fluid to degrade and flow back after treatment. Undegraded hydraulic fracturing fluid has always been a major issue, and is believed to drastically undermine the performance of hydraulically fractured wells. Several attempts have been made to quantify the damage associated with residual fluid, with varying level of success. Previous approaches may include lab experiments, numerical simulation and evaluation of production data. In this work, the previous investigation results has been accounted and further improvement is made in quantifying the cleanup of residual fluid and subsequent hydrocarbon recovery. After investigating fracture fluid damage mechanism, a simple mathematical model is developed to quantify residual fluid cleanup and its effect on the gas production from a tight gas sandstone reservoir. Key solutions have been derived with the help of Mathematica, and then a simple Excel-VBA code have also been developed to better characterize the cleanup process under different reservoir conditions, hydraulic fracture dimensions and varying residual fluid rheology. Contrary to the previous attempts we assume that the entire fracture is in a plugged initially. In addition to this we use a system approach and show that initially the available reservoir energy is used for establishing a narrow flow channel in the fracture, and the system approaches to its final productivity gradually. Results and analyses show that higher conductivity of hydraulic fracture does not ensure 100% cleanup; if sufficient energy is not available from the reservoir to overcome the resistance exhibited by the complex rheology of residual fluid along the fracture. This work provides a methodology that will help engineers to select the right fracturing fluid properties in tight gas. This is important because only in North America approximately 10,784Tcf of unconventional and gas reserves are present and more such reservoirs will be stimulated to fulfill the needs of future energy demand.Item Application of the Continuous EUR Method to Estimate Reserves in Unconventional Gas Reservoirs(2010-10-12) Currie, Stephanie M.Reserves estimation in unconventional (low/ultra-low permeability) reservoirs has become a topic of increased interest as more of these resources are being developed, especially in North America. The estimation of reserves in unconventional reservoirs is challenging due to the long transient flow period exhibited by the production data. The use of conventional methods (i.e., Arps' decline curves) to estimate reserves is often times inaccurate and leads to the overestimation of reserves because these models are only (theoretically) applicable for the boundary-dominated flow regime. The premise of this work is to present and demonstrate a methodology which continuously estimates the ultimate recovery during the producing life of a well in order to generate a time-dependent profile of the estimated ultimate recovery (EUR). The "objective" is to estimate the final EUR value(s) from several complimentary analyses. In this work we present the "Continuous EUR Method" to estimate reserves for unconventional gas reservoirs using a rate-time analysis approach. This work offers a coherent process to reduce the uncertainty in reserves estimation for unconventional gas reservoirs by quantifying "upper" and "lower" limits of EUR prior to the onset of boundary-dominated flow. We propose the use of traditional and new rate-time relations to establish the "upper" limit for EUR. We clearly demonstrate that rate-time relations which better represent the transient and transitional flow regimes (in particular the power law exponential rate decline relation) often lead to a more accurate "upper" limit for reserves estimates ? earlier in the producing life of a well (as compared to conventional ("Arps") relations). Furthermore, we propose a straight line extrapolation technique to offer a conservative estimate of maximum produced gas which we use as the "lower" limit for EUR. The EUR values estimated using this technique continually increase with time, eventually reaching a maximum value. We successfully demonstrate the methodology by applying the approach to 43 field examples producing from 7 different tight sandstone and shale gas reservoirs. We show that the difference between the "upper" and "lower" limit of reserves decreases with time and converges to the "true" value of reserves during the latter producing life of a well.Item Developing a tight gas sand advisor for completion and stimulation in tight gas reservoirs worldwide(2009-05-15) Bogatchev, Kirill Y.As the demand for energy worldwide increases, the oil and gas industry will need to increase recovery from unconventional gas reservoirs (UGR). UGRs include Tight Gas Sand (TGS), coalbed methane and gas shales. To economically produce UGRs, one must have adequate product price and one must use the most current technology. TGS reservoirs require stimulation as a part of the completion, so improvement of completion practices is very important. We did a thorough literature review to extract knowledge and experience about completion and stimulation technologies used in TGS reservoirs. We developed the principal design and two modules of a computer program called Tight Gas Sand Advisor (TGS Advisor), which can be used to assist engineers in making decisions while completing and stimulating TGS reservoirs. The modules include Perforation Selection and Proppant Selection. Based on input well/reservoir parameters these subroutines provide unambiguous recommendations concerning which perforation strategy(s) and what proppant(s) are applicable for a given well. The most crucial parameters from completion best-practices analyses and consultations with experts are built into TGS Advisor?s logic, which mimics human expert?s decision-making process. TGS Advisor?s recommended procedures for successful completions will facilitate TGS development and improve economical performance of TGS reservoirs.Item Optimizing Development Strategies to Increase Reserves in Unconventional Gas Reservoirs(2011-10-21) Turkarslan, GulcanThe ever increasing energy demand brings about widespread interest to rapidly, profitably and efficiently develop unconventional resources, among which tight gas sands hold a significant portion. However, optimization of development strategies in tight gas fields is challenging, not only because of the wide range of depositional environments and large variability in reservoir properties, but also because the evaluation often has to deal with a multitude of wells, limited reservoir information, and time and budget constraints. Unfortunately, classical full-scale reservoir evaluation cannot be routinely employed by small- to medium-sized operators, given its timeconsuming and expensive nature. In addition, the full-scale evaluation is generally built on deterministic principles and produces a single realization of the reservoir, despite the significant uncertainty faced by operators. This work addresses the need for rapid and cost-efficient technologies to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs. To achieve the research objectives, an integrated reservoir and decision modeling tool that fully incorporates uncertainty was developed. Monte Carlo simulation was used with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results were then fit with decline curves to enable direct integration of the reservoir model into a Bayesian decision model. These integrated tools were applied to the tight gas assets of Unconventional Gas Resources Inc. in the Berland River area, Alberta, Canada.Item Rate-decline Relations for Unconventional Reservoirs and Development of Parametric Correlations for Estimation of Reservoir Properties(2012-10-24) Askabe, Yohanes 1985-Time-rate analysis and time-rate-pressure analysis methods are available to estimate reserves and study flow performance of wells in unconventional gas reservoirs. However, these tools are often incorrectly used or the analysis can become difficult because of the complex nature of the reservoir system. Conventional methods (e.g., Arps' time-rate relations) are often used incorrectly to estimate reserves from such reservoirs. It was only recently that a serious study was conducted to outline the limitations of these relations and to set guidelines for their correct application. New time-rate relations, particularly the Duong and logistic growth model, were introduced to estimate reserves and forecast production from unconventional reservoirs. These new models are being used with limited understanding of their characteristics and limitations. Moreover, well performance analyses using analytical/semi-analytical solutions (time-rate-pressure) are often complicated from non-uniqueness that arises when estimating well/formation properties. In this work, we present a detailed study of the Duong model and logistic growth model to investigate the behaviors and limitations of these models when analyzing production data from unconventional reservoirs. We consider production data generated from numerical simulation cases and data obtained from unconventional gas reservoirs to study the quality of match to specific flow regimes and compare accuracy of the reserve estimates. We use the power-law exponential model (PLE), which has been shown to model transient, transition and boundary-dominated flow regimes reliably, as a benchmark to study performance of Duong and logistic growth models. Moreover, we use the "continuous EUR" approach to compare these models during reserve estimation. Finally, we develop four new time-rate relations, based on characteristics of the time-rate data on diagnostic plots. Using diagnostic plots we show that the new time-rate relations provide a quality match to the production data across all flow regimes, leading to a reliable reserve estimate. In a preliminary study, we integrated time-rate model parameters with fundamental reservoir properties (i.e., fracture conductivity (Fc) and 30 year EUR (EUR30yr)), by studying 15 numerical simulation cases to yield parametric correlations. We have demonstrated a methodology to integrate time-rate model parameters and reservoir properties. This method avoids the non-uniqueness issues often associated with model-based production data analysis. This study provides theoretical basis for further demonstration of the methodology using field cases.Item Stress-dependent permeability on tight gas reservoirs(Texas A&M University, 2005-02-17) Rodriguez, Cesar AlexanderPeople in the oil and gas industry sometimes do not consider pressure-dependent permeability in reservoir performance calculations. It basically happens due to lack of lab data to determine level of dependency. This thesis attempts to evaluate the error introduced in calculations when a constant permeability is assumed in tight gas reservoir. It is desired to determine how accurate are conventional pressure analysis calculations when the reservoir has a strong pressure-dependent permeability. The analysis considers the error due to effects of permeability and skin factor. Also included is the error associated when calculating Original Gas in Place in the reservoir. The mathematical model considers analytical and numerical solutions of radial and linear flow of gas through porous media. The model includes both the conventional method, which assumes a constant permeability (pressure-independent), and a numerical method that incorporates a pressure-dependent permeability. Analysis focuses on different levels of pressure draw down in a well located in the center of a homogeneous reservoir considering two types of flow field geometries: radial and linear. Two different producing control modes for the producer well are considered: constant rate and constant bottom hole pressure. Methodology consists of simulated tight gas well production with k(p) included. Then, we analyze results as though k(p) effects were ignored and finally, observe errors in determining permeability (k) and skin factor (s). Additionally, we calculate pore volume and OGIP in the reservoir. Analysis demonstrates that incorporation of pressure-dependence of permeability k(p) is critical in order to avoid inference of erroneous values of permeability, skin factor and OGIP from well test analysis of tight gas reservoirs. Estimation of these parameters depends on draw down in the reservoir. The great impact of permeability, skin factor and OGIP calculations are useful in business decisions and profitability for the oil company. Miscalculation of permeability and skin factor can lead to wrong decisions regarding well stimulation, which reduces well profitability. In most cases the OGIP calculated is underestimated. Calculated values are lower than the correct value. It can be taken as an advantage if we consider that additional gas wells and reserves would be incorporated in the exploitation plan.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.