Unconventional reservoirs are typically characterized by very low permeabilities, and thus, the pressure depletion from a producing well may not propagate far from the well during the life of a development. Currently, two approaches are widely utilized to perform unconventional reservoir analysis: analytical techniques, including the decline curve analysis and the pressure/rate transient analysis, and numerical simulation. The numerical simulation can rigorously account for complex well geometry and reservoir heterogeneity but also is time consuming. In this thesis, we propose and apply an efficient technique, fast marching method (FMM), to analyze the shale gas reservoirs. Our proposed approach stands midway between analytic techniques and numerical simulation. In contrast to analytical techniques, it takes into account complex well geometry and reservoir heterogeneity, and it is less time consuming compared to numerical simulation. The fast marching method can efficiently provide us with the solution of the pressure front propagation equation, which can be expressed as an Eikonal equation. Our approach is based on the generalization of the concept of depth of investigation. Its application to unconventional reservoirs can provide the understanding necessary to describe and optimize the interaction between complex multi-stage fractured wells, reservoir heterogeneity, drainage volumes, pressure depletion, and well rates. The proposed method allows rapid approximation of reservoir simulation results without resorting to detailed flow simulation, and also provides the time-evolution of the well drainage volume for visualization. Calibration of reservoir models to match historical dynamic data is necessary to increase confidence in simulation models and also minimize risks in decision making. In this thesis, we propose an integrated workflow: applying the genetic algorithm (GA) to calibrate the model parameters, and utilizing the fast marching based approach for forward simulation. This workflow takes advantages of both the derivative free characteristics of GA and the speed of FMM. In addition, we also provide a novel approach to incorporate the micro-seismic events (if available) into our history matching workflow so as to further constrain and better calibrate our models.

For a natural gas importing country, &ldquo / take or pay&rdquo / approach creates problems since the demand for natural gas varies during the year and the excess amount of natural gas should be stored. In this study, an underground gas storage project is evaluated in a depleted gas Field M. After gathering all necessary reservoir, fluid, production and pressure data, the data were adapted to computer language, which was used in a commercial simulator software (IMEX) that is the CMG&rsquo / s (Computer Modelling Group) new generation adoptive simulator, to reach the history matching. The history matching which consists of the 4 year of production of the gas reservoir is the first step of this study. The simulation program was able to accomplish a good history match with the given parameters of the reservoir. Using the history match as a base, five different scenarios were created and forecast the injection and withdrawal performance of the reservoir. These scenarios includes 5 newly drilled horizontal wells which were used in combinations with the existing wells. With a predetermined injection rate of 13 MMcf/D was set for all the wells and among the 5 scenarios, 5 horizontal &ndash / 6 vertical injectors &amp / 5 horizontal - 6 vertical producers is the most successful in handling the gas inventory and the time it takes for a gas injection and production period. After the determination of the well configuration, the optimum injection rate for the entire field was obtained and found to be 130 MMcf/D by running different injection rates for all wells and then for only horizontal wells different injection rates were applied with a constant injection rate of 130 MMcf/d for vertical wells. Then it has been found that it is better to apply the 5th scenario which includes 5 horizontal &ndash / 6 vertical injectors &amp / 5 horizontal - 6 vertical producers having an injection rate of 130 MMcf/d for horizontal and vertical wells. Since within the 5th scenario, changing the injection rate to 1.3 Bcf/d and 13 Bcf/d, did not effect and change the average reservoir pressure significantly, it is best to carry out the project with the optimum injection rate which is 130 MMcf/d. The total gas produced untill 2012 is 394 BCF and the gas injected is 340 BCF where the maximum average reservoir pressure was recovered and set into a new value of 1881 psi by injection and cushion gas pressure as 1371 psi by withdrawal. If 5th scenario is compared with the others, there is an increase in injection and production performance about 90%.

Thesis (Ph.D.)--University of Tulsa, 1993. / Includes bibliographical references (leaves 254-269).

The region I´ve chosen for my diploma thesis is situated on the border of Poberounská and Czech-Moravian system of geomorphological unit Bohemian Massif. It used to be one of the richest uranium mining district of Příbram region, and it is characterized by geological structure of central-Bohemian plutonium within the geological complex Bohemian Massif. On the contiguity of it there is found vast hydrothermal uranium deposit. This deposit is divided into 9 panels ? Třebsko, Kamenná, Lešetice, Brod, Jeruzalém, Háje, Svatá Hora, Bytíz, Skalka and Obořiště, which belong to the Příbram district. The town Příbram is famous for its long-standing mining tradition not only of polymetalic but above all of uranium ores. This tradition achieved the great success of world standards in the second half of the 20th century. There was revealed a lot of hydrothermal dikes containing requested uranite (black blende, nasturan) after the Second World War. This raw material was heading to Soviet Union. Uranium mining works initiated its epoch in 1949 and regular mining activities finished by the closing of the last shaft in 1991. In all the period of time there was mined 50200, 8 tones of uranium ore. Uranium deposit in Příbram can also take pride in the deepest shaft No. 16 with the depth of 1838, 4 m which is the shaft No. 16. In connection with the mining there was formed the life of local people and also the life of people from all Czechoslovakia who were setting off to seek a living there. Today all the shafts are closed and deluged in a natural way. In certain area of the deposit has been built cavern gas reservoir. No other mining will be possible in the future. The state enterprise Diamo realizes revitalization works on former mining panels and monitors the value of surrounding environment.

Submitted by Maria Cristina (library@lncc.br) on 2017-04-06T18:57:20Z No. of bitstreams: 1 thesisVolpatto.pdf: 4316650 bytes, checksum: 70380eace3eba66de52728f9d1d7ff89 (MD5) / Approved for entry into archive by Maria Cristina (library@lncc.br) on 2017-04-06T18:57:31Z (GMT) No. of bitstreams: 1 thesisVolpatto.pdf: 4316650 bytes, checksum: 70380eace3eba66de52728f9d1d7ff89 (MD5) / Made available in DSpace on 2017-04-06T18:57:40Z (GMT). No. of bitstreams: 1 thesisVolpatto.pdf: 4316650 bytes, checksum: 70380eace3eba66de52728f9d1d7ff89 (MD5) Previous issue date: 2016-06-14 / Agência Nacional do Petróleo, Gás Natural e Biocombustíveis / The present work aims at constructing a new sequential hydro-mechanical model of gas reservoirs. The new aspect of the proposed model lies on the derivation of new source terms in the subsystems of hydrodynamics and geomechanics. When compared with the fully-coupled formulation, where the two systems are solved simultaneously, the proposed formulation allows to explore the difference in the time-scales of the two phenomena. In addition the sequential formulation can be naturally extended to treat impermeable adjacent rocks and overcomes the problem of lack of stability in the impermeable regions of the geological formation. The formulation proposed based on the fixed stress split algorithm is unconditionally stable in the iterative procedure for coupling the two subsystems. This continuum problem is discretized by the Galerkin method coupled with fixed point algorithms to handle non-linearities present in the equation of state of the gas and in the coupling between the two subsystems. Numerical simulations are performed to illustrate the influence of geomechanical effects upon gas production. Comparisons between the well known one and two-way formulations are also presented. / O presente trabalho objetiva a construção de um novo modelo de acoplamento hidro-mecânico em reservatórios de gás. O aspecto inovador do modelo proposto reside na natureza sequencial do acoplamento, caracterizado pela decomposição do operador acoplado, levando ao surgimento de termos de fonte entre os subsistemas hidrodinâmica e geomecânico. Quando comparado com a formulação completamente acoplada, onde os dois sistemas são resolvidos simultaneamente, a formulação proposta permite a adoção de diferentes passos de tempo, extensão natural para descrever rochas adjacentes ao reservatório produtivo e não sofre de carência de estabilidade nas zonas impermeáveis da formação geológica. A formulação proposta, baseada no algoritmo “fixed stress split”, apresenta a propriedade de ser incondicionalmente estável no processo iterativo adotado na resolução dos dois subsistemas. A formulação sequencial é discretizada pelo método de Galerkin aliada com algoritmo de ponto fixo para tratar as não-linearidades presentes na equação de estado do gás e no acoplamento entre os dois subsistemas. Simulações numéricas são realizadas para ilustrar os efeitos geomecânicos sobre a produção de gás em reservatórios não convencionais de gás em folhelho. Comparações entre as formulações em uma-via e duas-vias, comumente discutidas em geomecânica de reservatórios, são apresentadas.

Modern reservoir management typically involves simulations of geological models to predict future recovery estimates, providing the economic assessment of different field development strategies. Integrating reservoir data is a vital step in developing reliable reservoir performance models. Currently, most effective strategies for traditional manual history matching commonly follow a structured approach with a sequence of adjustments from global to regional parameters, followed by local changes in model properties. In contrast, many of the recent automatic history matching methods utilize parameter sensitivities or gradients to directly update the fine-scale reservoir properties, often ignoring geological inconsistency. Therefore, there is need for combining elements of all of these scales in a seamless manner. We present a hierarchical streamline-assisted history matching, with a framework of global-local updates. A probabilistic approach, consisting of design of experiments, response surface methodology and the genetic algorithm, is used to understand the uncertainty in the large-scale static and dynamic parameters. This global update step is followed by a streamline-based model calibration for high resolution reservoir heterogeneity. This local update step assimilates dynamic production data. We apply the genetic global calibration to unconventional shale gas reservoir specifically we include stimulated reservoir volume as a constraint term in the data integration to improve history matching and reduce prediction uncertainty. We introduce a novel approach for efficiently computing well drainage volumes for shale gas wells with multistage fractures and fracture clusters, and we will filter stochastic shale gas reservoir models by comparing the computed drainage volume with the measured SRV within specified confidence limits. Finally, we demonstrate the value of integrating downhole temperature measurements as coarse-scale constraint during streamline-based history matching of dynamic production data. We first derive coarse-scale permeability trends in the reservoir from temperature data. The coarse information are then downscaled into fine scale permeability by sequential Gaussian simulation with block kriging, and updated by local-scale streamline-based history matching. he power and utility of our approaches have been demonstrated using both synthetic and field examples.

Carbon dioxide is one of the greenhouse gases which have strong impacts on the environment and its amount in the atmosphere is far beyond to be ignored. Carbon dioxide levels are projected to be reduced by sequestering it directly to the underground. High amounts of carbon dioxide can be safely stored in underground media for very long time periods. Storage in depleted gas reservoirs provides an option for sequestering carbon dioxide. In 2002, production of Kuzey Marmara gas reservoir has been stopped due to gas storage plans. Carbon dioxide sequestration in Kuzey Marmara field has been considered in this study as an alternative to the gas storage projects. Reservoir porosity and permeability maps were prepared with the help of Surfer software demo version. These maps were merged with the available Kuzey Marmara production information to create an input file for CMG-GEM simulator and a three dimensional model of the reservoir was created. History match of the field model was made according to the 1998-2002 production data to verify the similarity between the model and actual reservoir. Kuzey Marmara field is regarded as a candidate for future gas storage projects. The reservoir still contains producible natural gas. Four different scenarios were prepared by considering this fact with variations in the regional field properties and implemented into previously built simulation model. These scenarios primarily focus on sequestering carbon dioxide while producing as much as natural gas possible. After analyzing the results from the scenarios it is realized that / CO2 injection can be applied to increase natural gas recovery of Kuzey Marmara field but sequestering high rate CO2 emissions is found out to be inappropriate.