It is common for field models of tight gas reservoirs to include several wells with hydraulic fractures. These hydraulic fractures can be very long, extending for more than a thousand feet. A hydraulic fracture width is usually no more than about 0.02 ft. The combination of the above factors leads to the conclusion that there is a need to model hydraulic fractures in coarse grid blocks for these field models since it may be impractical to simulate these models using fine grids. In this dissertation, a method was developed to simulate a reservoir model with a single hydraulic fracture that passes through several coarse gridblocks. This method was tested and a numerical error was quantified that occurs at early time due to the use of coarse grid blocks. In addition, in this work, rules were developed and tested on using uniform fine grids to simulate a reservoir model with a single hydraulic fracture. Results were compared with the results from simulations using non-uniform fine grids.

This project is a research into the effect of gas condensate damage in hydraulically fractured wells. It is the result of a problem encountered in producing a low permeability formation from a well in South Texas owned by the El Paso Production Company. The well was producing a gas condensate reservoir and questions were raised about how much drop in flowing bottomhole pressure below dewpoint would be appropriate. Condensate damage in the hydraulic fracture was expected to be of significant effect. Previous attempts to answer these questions have been from the perspective of a radial model. Condensate builds up in the reservoir as the reservoir pressure drops below the dewpoint pressure. As a result, the gas moving to the wellbore becomes leaner. With respect to the study by El-Banbi and McCain, the gas production rate may stabilize, or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore. This current work has a totally different approach. The effects of reservoir depletion are minimized by introduction of an injector well with fluid composition the same as the original reservoir fluid. It also assumes an infinite conductivity hydraulic fracture and uses a linear model. During the research, gas condensate simulations were performed using a commercial simulator (CMG). The results of this research are a step forward in helping to improve the management of gas condensate reservoirs by understanding the mechanics of liquid build-up. It also provides methodology for quantifying the condensate damage that impairs linear flow of gas into the hydraulic fracture.

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.

Unconventional gas has become an important resource to help meet our future energy demands. Although plentiful, it is difficult to produce this resource, when locked in a massive sedimentary formation. Among all unconventional gas resources, tight gas sands represent a big fraction and are often characterized by very low porosity and permeability associated with their producing formations, resulting in extremely low production rate. The low flow properties and the recovery factors of these sands make necessary continuous efforts to reduce costs and improve efficiency in all aspects of drilling, completion and production techniques. Many of the recent improvements have been in well completions and hydraulic fracturing. Thus, the main goal of a hydraulic fracture is to create a long, highly conductive fracture to facilitate the gas flow from the reservoir to the wellbore to obtain commercial production rates. Fracture conductivity depends on several factors, such as like the damage created by the gel during the treatment and the gel clean-up after the treatment. This research is focused on predicting more accurately the fracture conductivity, the gel damage created in fractures, and the fracture cleanup after a hydraulic fracture treatment under certain pressure and temperature conditions. Parameters that alter fracture conductivity, such as polymer concentration, breaker concentration and gas flow rate, are also examined in this study. A series of experiments, using a procedure of “dynamical fracture conductivity test”, were carried out. This procedure simulates the proppant/frac fluid slurries flow into the fractures in a low-permeability rock, as it occurs in the field, using different combinations of polymer and breaker concentrations under reservoirs conditions. The result of this study provides the basis to optimize the fracturing fluids and the polymer loading at different reservoir conditions, which may result in a clean and conductive fracture. Success in improving this process will help to decrease capital expenditures and increase the production in unconventional tight gas reservoirs.

One of the major challenges in fracturing low permeability/tight/unconventional gas formations is the loss of frac water and well productivity due to fluid entrapment in the matrix or fracture. Field results have indicated that only 15-30% of the frac fluid is recovered at the surface after flow back is initiated. Past studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped due to the high capillary pressure in the matrix. Significant efforts have been made in the past to understand the impact of liquid blocking in hydraulically fractured conventional gas wells. Numerous remediation measures such as huff and puff gas cycling, alcohol or surfactant based chemical treatments have been proposed to reduce fracture face damage. However, when considering hydraulic fractures in unconventional reservoirs horizontal wells, the fluid may also be trapped within the fracture itself and may impact the cleanup as well as productivity. This study shows that under typical gas flow rates in tight / shale gas formations, liquid loading within the fractures is likely to occur. Most of the previous simulation studies consider a 2D reservoir model and ignore gravity, considering the high vertical anisotropy (or extremely low vertical permeability) in these tight reservoirs matrix. However, this study presents the results of 3D simulations of liquid loading in hydraulic fractures in horizontal wells, including gravity and capillary pressure effects. Both CMG IMEX and GEM have been used to study this phenomenon in dry and wet gas cases. The impact of drawdown, fracture and reservoir properties on liquid loading and well productivity is presented. Results show that low drawdown, low matrix permeability or low initial gas rates aggravate the liquid loading problem inside the fracture and thereby impact the cleanup and gas productivity during initial production. A clear understanding of the phenomena could help in selection of optimal production facilities and well profile. / text

Tight gas reservoirs provide almost one quarter of the current U.S. domestic gas production, with significant projected increases in the next several decades in both the U.S. and abroad. These reservoirs constitute an important play type, with opportunities for improved reservoir simulation & management, such as simulation model design, well placement. Our work develops robust and efficient strategies for improved tight gas reservoir simulation and management. Reservoir simulation models are usually acquired by upscaling the detailed 3D geologic models. Earlier studies of flow simulation have developed layer-based coarse reservoir simulation models, from the more detailed 3D geologic models. However, the layer-based approach cannot capture the essential sand and flow. We introduce and utilize the diffusive time of flight to understand the pressure continuity within the fluvial sands, and develop novel adaptive reservoir simulation grids to preserve the continuity of the reservoir sands. Combined with the high resolution transmissibility based upscaling of flow properties, and well index based upscaling of the well connections, we can build accurate simulation models with at least one order magnitude simulation speed up, but the predicted recoveries are almost indistinguishable from those of the geologic models. General practice of well placement usually requires reservoir simulation to predict the dynamic reservoir response. Numerous well placement scenarios require many reservoir simulation runs, which may have significant CPU demands. We propose a novel simulation-free screening approach to generate a quality map, based on a combination of static and dynamic reservoir properties. The geologic uncertainty is taken into consideration through an uncertainty map form the spatial connectivity analysis and variograms. Combining the quality map and uncertainty map, good infill well locations and drilling sequence can be determined for improved reservoir management. We apply this workflow to design the infill well drilling sequence and explore the impact of subsurface also, for a large-scale tight gas reservoir. Also, we evaluated an improved pressure approximation method, through the comparison with the leading order high frequency term of the asymptotic solution. The proposed pressure solution can better predict the heterogeneous reservoir depletion behavior, thus provide good opportunities for tight gas reservoir management.

La thèse porte sur la caractérisation des réservoirs non conventionnels. Elle cherche à intégrer paramètres sédimentologiques, diagénétiques et structuraux dans un réservoir gréseux "tight" pour prédire ses propriétés hydrauliques. Elle concerne la formation des "Quartzites de Hamra", un des réservoirs pétroliers les plus prolifiques des bassins paléozoïques algériens. Cette formation s’est déposée à l’Arenig dans un environnement marin peu profond. Elle a connu au cours de l’enfouissement une diagenèse siliceuse qui a modifié ses propriétés mécaniques et sa porosité. Les fractures, présentes à toutes les échelles, pallient aux faibles caractéristiques matricielles, et leur géométrie est peu précise. La thèse s’est focalisée sur deux cas de terrain, situés sur la zone de suture panafricaine et un champ à gaz localisé dans la partie centrale du bassin de l’Ahnet. L’étude pluridisciplinaire combine plusieurs approches allant de la télédétection aux analyses de laboratoire. Les résultats montrent que les «Quartzites» se sont déposés dans une rampe sableuse, soumise à une forte hydrodynamique tidale. Le système fracturé est en grande partie influencé par la présence des failles. La diagenèse siliceuse a été favorisée par la maturité minéralogique des faciès et leur richesse en quartz monocristallin. La principale source de silice est interne, et liée à la pression-dissolution. A cette histoire de la diagenèse succède une histoire complexe de la déformation, pendant laquelle on assiste à la création de veines en crack-seal, puis à des circulations hydrothermales, d’une précipitation dominée par les hydroxydes de fer et les phosphates. / This PHD subject is related to the "Characterization of nonconventional reservoirs". It’s purpose is to understand the interactions between sedimentary facies, fracturation and digenesis in a tight gas reservoir, in order to predict its hydraulic properties. This approach was applied to the "Quarzites de Hamra" formation, which is one of the most prolific reservoirs in the Algerian Paleozoic basins. This formation was deposited during Arenig time, in a shallow marine setting, and underwent during its burial history an important quartz cementation which modified its mechanical properties and porosity. Natural fractures are present at all levels and mitigate low matrix porosities, but their geometric attributes still poorly understood and difficult to predict. The thesis was focused on two field cases, located on the Panafrican suture zone, and a tight gas field located in the central part of Ahnet basin. The multi-disciplinary approach we used integrates satellite imagery, field and well data, and laboratory techniques. The results obtained show that the "Quarzites de Hamra" formation was deposited in a tidal clastic ramp. The fracture system is mainly controlled by the presence of faults. The quartz cementation was favored by the mineralogical maturity of the facies and their high mococristalline quartz content. The source of silica is internal, and related to pressure-solution phenomena. The digenetic history is succeeded by a complex history of deformation, during which a system of veins with crack-seal texture was created, followed by hydrothermal circulations resulting mainly in precipitation of phosphates and iron hydroxides.

Made available in DSpace on 2014-12-17T14:08:57Z (GMT). No. of bitstreams: 1 FranciscoPBJ_DISSERT.pdf: 5706323 bytes, checksum: 7e213d2df30615621d9d118318bdfa95 (MD5) Previous issue date: 2014-02-28 / Petr?leo Brasileiro SA - PETROBRAS / With the increasing of energetic consumption in the worldwile, conventional reservoirs, known by their easy exploration and exploitation, are not being enough to satisfy this demand, what has made necessary exploring unconventional reservoirs. This kind of exploration demands developing more advanced technologies to make possible to exploit those hydrocarbons. Tight gas is an example of this kind of unconventional reservoir. It refers to sandstone fields with low porosity, around 8%, and permeabilities between 0.1 and 0.0001 mD, which accumulates considerable amounts of natural gas. That natural gas can only be extracted by applying hydraulic fracturing, aiming at stimulating the reservoir, by creating a preferential way through the reservoir to the well, changing and making easier the flow of fluids, thus increasing the productivity of those reservoirs. Therefore, the objective of this thesis is analyzing the recovery factor of a reservoir by applying hydraulic fracturing. All the studies were performed through simulations using the IMEX software, by CMG (Computer Modelling Group), in it 2012.10 version / Com o crescimento do consumo energ?tico em todo o mundo, os reservat?rios convencionais, chamados de reservat?rios de f?cil explora??o e produ??o n?o est?o atendendo ? demanda energ?tica mundial, fazendo-se necess?rio a explora??o de reservas n?o convencionais. Esse tipo de explora??o exige o desenvolvimento de tecnologias mais avan?adas para a sua explota??o. Como exemplo dessas reservas, temos os reservat?rios do tipo Tight Gas, onde referem-se aos campos de arenito com baixa porosidade, na faixa de 8%, e permeabilidade na faixa entre 0,1 mD e 0,0001 mD, que acumulam consider?veis reservas de g?s natural, podendo apresentar viabilidade econ?mica para explota??o. O g?s natural nesse tipo de reservat?rio s? pode ser extra?do a partir da aplica??o da t?cnica de faturamento hidr?ulico, que tem por finalidade estimular o po?o, criando um canal de alta condutividade entre o po?o e o reservat?rio alterando e facilitando o fluxo de fluidos, aumentando assim a produtividade do reservat?rio. Assim, o objetivo desse trabalho ? analisar o fator de recupera??o do reservat?rio com a aplica??o do fraturamento hidr?ulico. Os estudos foram realizados atrav?s de simula??es concretizadas no m?dulo IMEX do programa da CMG (Computer Modelling Group), vers?o 2012.10

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.

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.