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1
Whaballa, Ala. "Reservoir simulation and well testing of compartmentalized reservoirs." Thesis, Heriot-Watt University, 1991. http://hdl.handle.net/10399/1493.
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Wang, Linna. "Reservoir simulation study for the South Slattery Field." Laramie, Wyo. : University of Wyoming, 2007. http://proquest.umi.com/pqdweb?did=1400965521&sid=1&Fmt=2&clientId=18949&RQT=309&VName=PQD.
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Ahmed, Elfeel Mohamed. "Improved upscaling and reservoir simulation of enhanced oil recovery processes in naturally fractured reservoirs." Thesis, Heriot-Watt University, 2014. http://hdl.handle.net/10399/2755.
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Naturally fractured reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now considered for Enhanced Oil Recovery (EOR) schemes that involve three-phase flow such as water-alternating-gas (WAG) injection. Accurate numerical simulation of flow in NFR is essential for sound reservoir management decisions to maximise oil recovery and minimise the cost of field development. In this thesis, two important issues related to flow simulation in NFR are investigated. First, a step-wise upscaling approach is developed to evaluate the accuracy of dual porosity models in estimating matrix-fracture transfer duringWAG injection. It was found that the classical dual porosity models generally overestimate recovery from matrix blocks. Hence, a double block model was developed and extended to a multi-rate dual porosity (MRDP). The multi-rate double block model showed significant improvements in matching detailed fine grid simulations of three-phase matrix-fracture transfer. Second, the accuracy of upscaling discrete fracture networks (DFN) is assessed and its impact on history matching was investigated on a real fractured reservoir. A new method to upscale the shape factors needed for MRDP models from DFN is presented. This method is a notable step towards more accurate but still efficient reservoir simulation in NFR.
4
Balland, Philippe. "The solenoidal finite element method and reservoir simulation." Thesis, University of Oxford, 1994. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.260727.
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Gessel, Gregory M. "A New Method for Treating Wells in Reservoir Simulation." Diss., CLICK HERE for online access, 2007. http://contentdm.lib.byu.edu/ETD/image/etd1902.pdf.
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Pamukcu, Yusuf Ziya. "Simulating Oil Recovery During Co2 Sequestration Into A Mature Oil Reservoir." Master's thesis, METU, 2006. http://etd.lib.metu.edu.tr/upload/3/12607418/index.pdf.
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The continuous rising of anthropogenic emission into the atmosphere as a consequence of industrial growth is becoming uncontrollable, which causes heating up the atmosphere and changes in global climate. Therefore, CO2 emission becomes a big problem and key issue in environmental concerns.
There are several options discussed for reducing the amount of CO2 emitted into the atmosphere. CO2 sequestration is one of these options, which involves the capture of CO2 from hydrocarbon emission sources, e.g. power plants, the injection and storage of CO2 into deep geological formations, e.g. depleted oil reservoirs. The complexity in the structure of geological formations and the processes involved in this method necessitates the use of numerical simulations in revealing the potential problems, determining feasibility, storage capacity, and life span credibility.
Field K having 32o API gravity oil in a carbonate formation from southeast Turkey was studied. Field K was put on production in 1982 and produced until 2006, which was very close to its economic lifetime. Thus, it was considered as a candidate for enhanced oil recovery and CO2 sequestration.
Reservoir rock and fluid data was first interpreted with available well logging, core and drill stem test data. Monte Carlo simulation was used to evaluate the probable reserve that was 7 million STB, original oil in place (OOIP). The data were then merged into CMG/STARS simulator. History matching study was done with production data to verify the results of the simulator with field data. After obtaining a good match, the different scenarios were realized by using the simulator.
From the results of simulation runs, it was realized that CO2 injection can be applied to increase oil recovery, but sequestering of high amount of CO2 was found out to be inappropriate for field K. Therefore, it was decided to focus on oil recovery while CO2 was sequestered within the reservoir. Oil recovery was about 23% of OOIP in 2006 for field K, it reached to 43 % of OOIP by injecting CO2 after defining production and injection scenarios, properly.
7
Susuz, Onur. "Assessment Of Reservoir Rock And Fluid Data For Black Oil Simulation." Master's thesis, METU, 2010. http://etd.lib.metu.edu.tr/upload/2/12611561/index.pdf.
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Reservoir simulation studies are one of the key tools in an integrated reservoir management study. A successful reservoir simulation application requires representative input data for reservoir rock and fluid properties. This study aims to develop a road map from laboratory measurements to the input data file of reservoir simulation and to make a probabilistic approach for the estimation of unknown parameters. Raw data of reservoir rock and fluid properties of a selected oil field of Turkey will be interpreted and prepared in a way that they will be used as input data of a simulator.
8
Papadopoulos, Andreas-Theodoros. "Block smoothed aggregation algebraic multigrid preconditioners for oil reservoir simulation systems." Thesis, University of Oxford, 2004. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.409174.
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Hird, Kirk B. "A conditional simulation method for reservoir description using geological and well performance constraints /." Access abstract and link to full text, 1993. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9330024.
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Guehria, Fawzie M. "A new efficient fully integrated approach to compositional reservoir simulation /." Access abstract and link to full text, 1991. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9203795.
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Gozalpour, Fathollah. "Integrated phase behaviour modelling of petroleum fluids for compositional simulation of reservoir-surface processes." Thesis, Heriot-Watt University, 1998. http://hdl.handle.net/10399/1199.
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SOLANO, ALEJANDRA CAMACHO. "UNCERTAINTY QUANTIFICATION IN OIL RESERVOIR SIMULATION VIA GENETIC PROGRAMMING AND CHAOS POLYNOMIAL." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2015. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=26216@1.
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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIROCOORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIOR
PROGRAMA DE EXCELENCIA ACADEMICA
Os modelos de simulação de reservatórios estão sujeitos à incerteza presente em uma grande variedade de seus parâmetros de entrada. Esta incerteza é o resultado da heterogeneidade das formações geológicas, erros nas medições dos dados e da modelagem petrofísica, estrutural e do transporte dos fluidos no meio poroso. Uma quantificação precisa da incerteza requer, na maioria dos casos, uma quantidade elevada de simulações, o que é usualmente inviável se considerarmos o tempo consumido para simular modelos de grande escala. Por outro lado, uma avaliação adequada da incerteza aumenta a qualidade e robustez das decisões tomadas para o gerenciamento dos campos de petróleo. Com esta motivação, foi investigado o método das Expansões por Caos Polinomial (PCE, por suas siglas em inglês). PCE é uma técnica de convergência rápida utilizada para analisar como se propaga, na saída de um modelo, a incerteza presente nos parâmetros de entrada. Mediante PCE, pode-se representar a resposta aleatória de um modelo de simulação de reservatórios de petróleo como um polinômio, construído a partir de uma base de funções que dependem da distribuição de probabilidade das variáveis incertas de entrada. Por outro lado, quando a relação entre os parâmetros de entrada e a saída do modelo têm um componente não polinomial, o algoritmo de Programação Genética (PG) pode ser utilizado para representar esta dependência utilizando funções ou operadores mais complexos. PG é um algoritmo de regressão simbólica capaz de encontrar uma expressão aleatória explícita, que aproxime a saída de um modelo de simulação de reservatórios de petróleo, conhecendo-se a priori a distribuição de probabilidade dos parâmetros de entrada. Neste trabalho foram aplicadas as duas técnicas, antes mencionadas, num modelo de simulação de reservatórios baseado no campo PUNQ-S3, considerando até vinte e três parâmetros incertos durante um período de produção de 13 anos. Foi feita uma análise de incerteza, calculando-se a distribuição de probabilidade completa da saída do simulador. Os resultados foram comparados com o método de Monte Carlo, indicando um alto desempenho em termos de custo computacional e acurácia. Ambas as técnicas conseguem níveis de ajuste superiores a 80 porcento com uma quantidade de simulações consideravelmente baixa.
Reservoir simulation models are subject to uncertainty in a wide variety of its inputs. This uncertainty is a result of the heterogeneity of the geological formations, data measurement errors, and petrophysical, structural, and fluid transport in porous media modelling. An accurate uncertainty quantification requires, in most cases, a large number of simulations, which is unviable considering the time it takes to simulate large scale models. On the other hand, a proper uncertainty assessment, increases the robustness of the decision making process for the oil field management. To this end, the method of Polynomial Chaos Expansions (PCE) was studied. PCE is a fast paced convergence technique, used to analyze the uncertainty propagation of the input parameters all the way to the output of the model. Through PCE is possible to represent the response of an oil reservoir simulation model as a polynomial, built from a function basis, that depend on the probability distribution of the uncertain input variables. Furthermore, when the relationship between the input and output parameters of the model has a non-polynomial component, the algorithm of Genetic Programming (GP) can be used to represent this dependency by more elaborate functions or operators. GP is a symbolic regression algorithm, capable of finding an explicit expression that approximates the output of a reservoir simulation model, with prior knowledge of the probability distribution of the input parameters. In this work, the two previously mentioned techniques were applied in a reservoir simulation model, based on the oil field PUNQ-S3, considering up to twenty three uncertain parameters during a simulation period of 13 years. An uncertainty analysis of the output of the simulator was conducted, calculating the entire probability distribution. The results were compared to the Monte Carlo simulation method, presenting a satisfactory performance in terms of accuracy and computational cost. Both techniques show adjustment levels higher than 80 percent, with a considerable small amount simulations.
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Dicks, Edwin Michael. "Higher order Godunov black-oil simulations for compressible flow in porous media." Thesis, University of Reading, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.333614.
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Gholami, Vida. "Fuzzy rock typing enhancing reservoir simulation and modeling by honoring high resolution geological models /." Morgantown, W. Va. : [West Virginia University Libraries], 2009. http://hdl.handle.net/10450/10555.
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Thesis (M.S.)--West Virginia University, 2009.Title from document title page. Document formatted into pages; contains xiii, 120 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 89-93).
15
Folefac, A. N. "Reservoir simulation of heavy oil recovery by hot fluid injection in horizontal wells." Thesis, Imperial College London, 1988. http://hdl.handle.net/10044/1/11372.
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Gil, Edison. "Improving the simulation of a waterflooding recovery process using artificial neural networks." Morgantown, W. Va. : [West Virginia University Libraries], 2000. http://etd.wvu.edu/templates/showETD.cfm?recnum=1662.
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Thesis (M.S.)--West Virginia University, 2000.Title from document title page. Document formatted into pages; contains xi, 94 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 63-64).
17
Gaviria, Garcia Ricardo. "Reservoir simulation of co2 sequestration and enhanced oil recovery in Tensleep Formation, Teapot Dome field." Texas A&M University, 2005. http://hdl.handle.net/1969.1/3083.
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Teapot Dome field is located 35 miles north of Casper, Wyoming in Natrona County.
This field has been selected by the U.S. Department of Energy to implement a field-size
CO2 storage project. With a projected storage of 2.6 million tons of carbon dioxide a
year under fully operational conditions in 2006, the multiple-partner Teapot Dome
project could be one of the world's largest CO2 storage sites.
CO2 injection has been used for decades to improve oil recovery from depleted
hydrocarbon reservoirs. In the CO2 sequestration technique, the aim is to "co-optimize" CO2 storage and oil recovery.
In order to achieve the goal of CO2 sequestration, this study uses reservoir simulation to predict the amount of CO2 that can be stored in the Tensleep Formation and the amount of oil that can be produced as a side benefit of CO2 injection. This research discusses the effects of using different reservoir fluid models from EOS
regression and fracture permeability in dual porosity models on enhanced oil recovery
and CO2 storage in the Tensleep Formation. Oil and gas production behavior obtained
from the fluid models were completely different. Fully compositional and pseudo-miscible black oil fluid models were tested in a quarter of a five spot pattern. Compositional fluid model is more convenient for enhanced oil recovery evaluation. Detailed reservoir characterization was performed to represent the complex characteristics of the reservoir. A 3D black oil reservoir simulation model was used to evaluate the effects of fractures in reservoir fluids production. Single porosity simulation model results were compared with those from the dual porosity model. Based on the results obtained from each simulation model, it has been concluded that the pseudo-miscible model can not be used to represent the CO2 injection process in Teapot Dome. Dual porosity models with variable fracture permeability provided a better
reproduction of oil and water rates in the highly fractured Tensleep Formation.
18
Al-Suwaidan, Tareq Mohammad. "Effect of the presence of tar mat on the performance of an oil reservoir, a simulation study /." Access abstract and link to full text, 1990. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9034354.
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Atthawutthisin, Natthaporn. "Numerical Simulation of Low Salinity Water Flooding Assisted with Chemical Flooding for Enhanced Oil Recovery." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19113.
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World proved oil reserve gradually decreases due to the increase production but decrease new field discovery. The focus on enhance oil recovery from the existing fields has become more interesting in the recent years. Since waterflooding has been used in practices in secondary recovery phase for long time ago, the low salinity waterflooding is possible to apply as tertiary recovery phase. Another effective enhance oil recovery method is chemical flooding especially, nowadays, when the price of chemical is not a big issue compared to oil price. Both low salinity and chemical flooding method have been trialed and success in laboratory studies and some field tests. Moreover the salinity sensitivity on chemical flooding has been studied and both positive and negative results were proposed. Because new technology has been developing day by day in order to get higher oil recovery, the new technology as the combination of low salinity waterflooding and chemical flooding has been studied in this report. In this thesis, the literature of low salinity water flooding, alkaline flooding, surfactant flooding, polymer flooding and alkaline-surfactant-polymer flooding (ASP) have been reviewed. The mechanisms of each method that affect to oil recovery and salinity sensitivity on each chemical flooding method have been summarized. All of those studies showed the benefit of chemical to the low salinity water flooding. the result of literature reviews has turned to the numerical simulation part.The simulation has been carried out on a 3 dimensional synthetic model by using Eclipse 100 as the simulator. The model is heterogeneous with patterns variation in permeability and porosity. The effect of low salinity in water flooding, alkaline flooding, surfactant flooding, polymer flooding and ASP flooding have been observed in many aspects.The main role of low salinity effect in water flooding is wettability changing from oil-wet to water-wet. The low salinity water in the first water flooding phase give the positive effect but not much different compared to overall recovery. The low salinity in chemical solution influences an additional oil recovery in all combinations. Mainly, low salinity increases polymer solution viscosity that can improve sweep efficiency of polymer flooding. In alkaline flooding and surfactant flooding, the salinity is need to be optimized to optimum salinity condition corresponding to optimum alkaline concentration and surfactant concentration, where creates the lowest IFT. The range of secondary flooding for alkaline and surfactant flooding is when they reach the optimum concentration. In case of polymer, the viscous polymer solution can impact longer as the polymer injection range. In term of low salinity in tertiary water flooding, it influences better oil recovery than high salinity water flooding. Therefore, it can be concluded that low salinity water flooding gives a positive effect to overall result when combined with chemical flooding. The recommendations are also available for further study.
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Li, Bowei. "Implementation of full permeability tensor representation in a dual porosity reservoir simulator." Access restricted to users with UT Austin EID Full text (PDF) from UMI/Dissertation Abstracts International, 2001. http://wwwlib.umi.com/cr/utexas/fullcit?p3034930.
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Wijaya, Zien. "CO2 Injection in an Oil Reservoir with Gas Cap (Compositional Simulation Case at Heidrun Field Norway)." Thesis, Norwegian University of Science and Technology, Department of Petroleum Engineering and Applied Geophysics, 2006. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-1635.
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A potential problem with CO2 Injection in oil reservoirs with gas caps is that gas cap may be contaminated by CO2. This could be an issue on the Heidrun Field where down dip using CO2-WAG is considered. Compositional reservoir simulations should be performed to investigate if the injected CO2 will form a stable CO2 layer below the hydrocarbon gas cap or if the CO2 will be mixed with the hydrocarbon gas before or during the production of the gas cap.
The project thesis will be started with an existing black oil sector model (from Upper Tilje Formation in Segment H and I form Heidrun field). The sector model (or a part of it) should first be converted to a compositional model (Eclipse 300) using an existing equation of state. A number of predictions should be performed, starting with down dip WAG at constant reservoir pressure followed by depletion of the gas cap. The project thesis will discuss also how to optimize the amount of gas that can be produced before CO2 breakthrough by considering different alternatives for gas production wells. Other sensitivities like gas production rate, well location, changing perforation interval and diffusion should be evaluated.
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de, La Porte Jacoba. "Sensitivities to component characterizations of heavy oil viscosity in numerical reservoir simulation of steam-injection processes." Thesis, Imperial College London, 2013. http://hdl.handle.net/10044/1/11056.
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This work examines heavy oil viscosity modelling during simulation of steam injection processes, such as steam-line-drive and SAGD, and the sensitivity of oil recovery predictions to the uncertainty in the oil viscosity. Analytical models to predict the sensitivity have been developed, confirmed by numerical simulation. Heavy oil compositional component viscosities are modelled with the Free Volume model. The model is extended in this thesis to estimate the viscosities of long-chain n-alkanes from C6H14 to C45H92 within an accuracy of 10% in the temperature range 27 to 300 °C (80 to 575 °F) and pressure range 0.1 to 120 MPa (14.5 to 17,400 psi). It estimates viscosities of long-chain n-alkanes up to C64H130 to within 30%. Extrapolated Free Volume molecular characteristic parameters, optimised based on available viscosity measurements for n-alkanes up to C64H130, are provided, and are the recommended values for use in heavy oil simulation. A heavy pseudo-component, representing a combination of asphaltenes and resins, which are the compounds responsible for the high viscosities observed in heavy oil, is characterised in terms of molecular weight, shape and activation energy for viscous flow. A method to predict its viscosity as a function of its physical properties, pressure and temperature, using the Free Volume model, is demonstrated. A density model based on the Tait model is extended, to predict the long-chain heavy oil compositional component densities within an accuracy of 3%, in the same temperature and pressure ranges as above. A grouping procedure is demonstrated to achieve oil recovery results comparable to a 24-component simulation case, using two pseudo-components. Key is the mixing equation used to calculate the oil phase viscosity as components are grouped. The Arrhenius mixing equation is evaluated for accuracy in predicting hydrocarbon mixture viscosities. Guidelines for accurate use are provided, while mixtures with CO2 are shown to require a different method.
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Delicado, Victor Edward. "A comparison of black-oil versus compositional simulation methods for evaluating a rich gas-condensate reservoir." University of the Western Cape, 2016. http://hdl.handle.net/11394/5860.
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Magister Scientiae - MScOver time, researchers have endeavoured to use conventional black-oil (BO) models to model volatile-oil and gas-condensate reservoirs as accurately as possible, with variable levels of success. The black-oil approach allows for the implementation of a simpler and less expensive computational algorithm than that associated with a compositional model. The first-mentioned can result in substantial time-saving in full field studies. This project evaluates the use of modified black-oil (MBO) as well as compositional (equation of state- EOS) approaches to determine the expected recovery and performance of a rich gascondensate reservoir. After initialization, the models reflected very similar in-place hydrocarbon volumes, with a deviation percentage of less than 5 % between the two modelling approaches.
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Abadli, Farid. "Simulation Study of Enhanced Oil Recovery by ASP (Alkaline, Surfactant and Polymer) Flooding for Norne Field C-segment." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19432.
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This research is a simulation study to improve total oil production using ASP flooding method based on simulation model of Norne field C-segment. The black oil model was used for simulations. Remaining oil in the reservoir can be divided into two classes, firstly residual oil to the water flood and secondly oil bypassed by the water flood. Residual oil mainly contains capillary trapped oil. Water flooding only is not able to produce capillary trapped oil so that there is a need for additional technique and force to produce as much as residual oil. One way of recovering this capillary trapped oil is by adding chemicals such as surfactant and alkaline to the injected water. Surfactants are considered for enhanced oil recovery by reduction of oil–water interfacial tension (IFT). The crucial role of alkali in an alkaline surfactant process is to reduce adsorption of surfactant during displacement through the formation. Also alkali is beneficial for reduction of oil-water IFT by in situ generation of soap, which is an anionic surfactant. Generally alkali is injected with surfactant together. On the other hand, polymer is very effective addition by increasing water viscosity which controls water mobility thus improving the sweep efficiency.In the first place, ASP flooding was simulated and studied for one dimensional, two dimensional and three dimensional synthetic models. All these models were built based on C-segment rock properties and reservoir parameters. Based on test runs, well C-3H was selected and used as a main injector in order to execute chemical injection schemes in the C-segment. Five studies such as polymer flooding, surfactant flooding, surfactant-polymer flooding, alkaline-surfactant and alkaline-surfactant-polymer flooding were considered in the injection process and important results from simulator were analyzed and interpreted. Sensitivity analyses were done especially focusing on chemical solution concentration, injection rate and duration of injection time. The polymer flooding project in this study has shown a better outcome compared to water flooding project. Economically best ASP solution flooding case is the flooding with concentration of alkaline at1.5kg/m3, surfactant at 15kg/m3 and polymer at 0.35 kg/m3 injecting for 5 years. AS flooding case for 4 years with alkali concentration at 0.5kg/m3 and surfactant concentration at 25 kg/m3 gave highest NPV value. It was found that surfactant flooding has a promising effect and it is more profitable than polymer flooding for the C segment in terms of NPV. Economic sensitivity analysis (Spider diagram) for low case, base case and high case at different oil prices, chemicals prices, and discount rate were also presented. It was found that change in oil price has significant effect on NPV compared to other parameters while polymer price has the least effect on NPV for high and low cases.
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Hardy, Benjamin Arik. "A New Method for the Rapid Calculation of Finely-Gridded Reservoir Simulation Pressures." Diss., CLICK HERE for online access, 2005. http://contentdm.lib.byu.edu/ETD/image/etd1123.pdf.
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Samadov, Hidayat. "Analyzing Reservoir Thermal Behavior By Using Thermal Simulation Model (sector Model In Stars)." Master's thesis, METU, 2011. http://etd.lib.metu.edu.tr/upload/12613336/index.pdf.
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It is observed that the flowing bottom-hole temperature (FBHT) changes as a result of production, injection or shutting the well down. Variations in temperature mainly occur due to geothermal gradient, injected fluid temperature, frictional heating and the Joule-Thomson effect. The latter is the change of temperature because of expansion or compression of a fluid in a flow process involving no heat transfer or work. CMG STARS thermal simulation sector model developed in this study was used to analyze FBHT changes and understand the reasons. Twenty three main and five additional cases that were developed by using this model were simulated and relation of BHT with other parameters was investigated. Indeed the response of temperature to the change of some parameters such as bottom-hole pressure and gas-oil ratio was detected and correlation was tried to set between these elements. Observations showed that generally FBHT increases when GOR decreases and/or flowing bottom-hole pressure (FBHP) increases. This information allows estimating daily gas-oil ratios from continuously measured BHT. Results of simulation were compared with a real case and almost the same responses were seen. The increase in temperature after the start of water and gas injection or due to stopping of neighboring production wells indicated interwell communications. Additional cases were run to determine whether there are BHT changes when initial temperature was kept constant throughout the reservoir. Different iteration numbers and refined grids were used during these runs to analyze iteration errorshowever no significant changes were observed due to iteration number differences and refined grids. These latter cases showed clearly that variations of temperature don&rsquo
t occur only due to geothermal gradient, but also pressure and saturation changes. On the whole, BHT can be used to get data ranging from daily gas-oil ratios to interwell connection if analyzed correctly.
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Sarkar, Sume. "Evaluation of Alkaline, Surfactant and Polymer Flooding for Enhanced Oil Recovery in the Norne E-segment Based on Applied Reservoir Simulation." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19958.
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The world needs energy – and over the short and medium term it is clear that much of our global energy consumption will come from fossil sources such as oil, gas and coal. With the current growing demand for oil led by major energy consuming countries such as China and India, securing new oil resources is a critical challenge for the oil industry. Each year, new production is needed to compensate the natural decline of existing wells, and the additional production required to satisfy the yearly demand for hydrocarbon energy that will represent approximately 9% of the worldwide total production. For this growth to be sustainable, a strong focus will have to be placed on finding new discoveries and/or optimizing oil production from current resources. The cost associated with the first option is significant. Therefore, reservoir management teams all over the world will have to cater for this demand mainly by maximizing hydrocarbon recovery factors through Enhanced Oil Recovery (EOR) processes. EOR consists of methods aimed at increasing ultimate oil recovery by injecting appropriate agents not normally present in the reservoir, such as chemicals, solvents, oxidizers and heat carriers in order to induce new mechanisms for displacing oil. Chemical flooding is one of the most promising and broadly applied EOR processes which have enjoyed significant research and pilot testing during the 1980s with a significant revival in recent years. However, its commercial implementation has been facing several technical, operational and economic challenges. Chemical flooding is further subdivided into polymer flooding, surfactant flooding, alkaline flooding, miscellar flooding, alkaline-surfactant-polymer (ASP) flooding. ASP flooding is a form of chemical enhanced oil recovery (EOR) that can allow operators to extend reservoir pool life and extract incremental reserves currently inaccessible by conventional EOR techniques such as waterflooding. Three chemical inject in the ASP process which is synergistic. In the ASP process, Surfactants are chemicals that used to reduce the interfacial tension between the involved fluids, making the immobile oil mobile. Alkali reduces adsorption of the surfactant on the rock surfaces and reacts with acids in the oil to create natural surfactant. Polymer improves the sweep efficiency. By simulating ASP flooding for several cases, with different chemical concentrations, injection length, time of injection, current well optimization and new well placement, this report suggests a number of good alternatives. Simulations showed that the most effective method was not the most profitable. From the simulation results and economic analysis, ASP flooding can be a good alternative for the Norne E-segment. But the margins are not significant, so fixed costs (such as equipment rental) will be of crucial importance.
28
Mago, Alonso Luis. "Adequate description of heavy oil viscosities and a method to assess optimal steam cyclic periods for thermal reservoir simulation." Thesis, Texas A&M University, 2003. http://hdl.handle.net/1969.1/3951.
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A global steady increase of energy consumption coupled with the decline of conventional oil resources points to a more aggressive exploitation of heavy oil. Heavy oil is a major source of energy in this century with a worldwide base reserve exceeding 2.5 trillion barrels. Management decisions and production strategies from thermal oil recovery processes are frequently based on reservoir simulation. A proper description of the physical properties, particularly oil viscosity, is essential in performing reliable modeling studies of fluid flow in the reservoir. We simulated cyclic steam injections on the highly viscous Hamaca oil, with a viscosity of over 10,000 cp at ambient temperature, and the production was drastically impacted by up to an order of magnitude when using improper mixing rules to describe the oil viscosity. This thesis demonstrates the importance of these mixing rules and alerts reservoir engineers to the significance of using different options simulators have built in their platforms to describe the viscosity of heavy oils. Log linear and power mixing rules do not provide enough flexibility to describe the viscosity of extra heavy oil with temperature. A recently implemented mixing rule in a commercial simulator has been studied providing satisfactory results. However, the methodology requires substantial interventions, and cannot be automatically updated. We provide guidelines to improve it and suggest more flexible mixing rules that could easily be implemented in commercial simulators. We also provide a methodology to determine the adequate time for each one of the periods in cyclic steam injection: injection, soaking and production. There is a lot of speculation in this matter and one of the objectives of this thesis is to better understand and provide guidelines to optimize oil production using proper lengths in each one of these periods. We have found that the production and injection periods should be similar in time length. Nevertheless, the production period should not be less than the injection period. On the other hand, the soaking period should be as short as possible because it is unproductive time in terms of field oil production for the well and therefore it translates into a negative cash flow for a company.
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Pimenta, Raquel Ribeiro Gomes 1978. "Seleção da estratégia de produção de um reservatório fraturado sob incerteza." [s.n.], 2014. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265734.
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Orientador: Denis José SchiozerDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: O sucesso econômico de projetos e o desenvolvimento de campos de petróleo dependem não só de atributos de reservatório como também de estratégias de produção. Em reservatórios naturalmente fraturados uma combinação de atributos como: conectividade de fraturas alta, influxo de aquífero forte e molhabilidade variável com parâmetros de projetos como injeção de água, podem resultar na chegada antecipada de água e até mesmo no fracasso do projeto. Os atributos de reservatórios geralmente não são conhecidos no momento da elaboração dos projetos quando a maior parte do investimento é efetuada; para campos marítimos, há ainda pouca flexibilidade para mudanças ao longo do tempo. A avaliação do risco envolvido então se torna muito importante. O resultado de projetos com reservatórios naturalmente fraturados depende muito da estratégia de produção, principalmente do número e da localização de poços. A otimização destes parâmetros aumenta a produção de óleo e a rentabilidade dos projetos. Esta dissertação apresenta uma metodologia de seleção de estratégia de produção que incorpora a análise de risco. As incertezas de reservatório são quantificadas e são selecionados três modelos para representar a variabilidade técnica e financeira. Estes modelos são usados como apoio para a seleção de estratégias de produção sob incertezas. Para este fim, primeiro se faz uma análise de risco onde se escolhem os denominados modelos de reservatórios variados, depois se escolhe uma estratégia de produção através de um estudo comparativo com diferentes métodos de explotação e, por fim, faz-se um estudo da robustez da estratégia escolhida para cada caso através da realização de uma análise de incerteza. No estudo comparativo de estratégias de produção são avaliados os métodos de depleção, injeção de água, gás, água e gás e alternada de água e gás e cada estratégia citada acima é otimizada de maneira assistida. Conclui-se que o estudo atinge o objetivo principal, já que a estratégia de injeção de água e gás é escolhida como a melhor estratégia de produção através da aplicação da metodologia de análise de risco. Esta estratégia é escolhida porque tem o maior valor presente líquido, o menor risco financeiro e ainda apresenta flexibilidade de projeto
Abstract: Economical results of an oilfield development depend on both reservoir attributes and strategy selection. For instance, water injection implementation in naturally fractured reservoir can result in early water production and poor economical results if this reservoir has high fracture connectivity, aquifer influx and mixed wettability. Reservoir attributes are generally unknown at the beginning of the project, when most of the investment is made. Since there is no much flexibility for changes during a life cycle of an offshore field, risk analysis is very important at this moment. Optimization of project parameters such as production strategy, well number and well location usually increase oil production and project profitability. This study presents a methodology to select the best production strategy incorporating risk analysis. Reservoir uncertainties are evaluated and all technical and financial variability are resumed in three models. This task is performed using the following steps: risk analysis where three models are selected among five hundred; production strategies comparison and finally a robust test using a complete risk analysis for all three models. The evaluations of the following production strategies are performed: depletion, water injection, gas injection, water and gas injection and water alternating gas injection. Each strategy is optimized using assisted technics and the best economical result is selected for development. This study results are successful and concludes that water and gas injection is the best strategy for this reservoir since it has the highest net present value, the lowest financial risk and adds project flexibility because it injects two different fluids
Mestrado
Reservatórios e Gestão
Mestra em Ciências e Engenharia de Petróleo
30
Yskak, Aidos. "Extra Korolev Producers: Their Impact On Production." Master's thesis, METU, 2010. http://etd.lib.metu.edu.tr/upload/12612448/index.pdf.
Full textAbstract:
In this study, a three-dimensional, three-phase dynamic simulation model based on geological investigations of Korolev oilfield in Kazakhstan was used as a development planning tool in order to improve performance of three new wells.
The model, developed previously by means of a seismic study, well log and core data, incorporating with characteristics of oilfield productivity, properties of reservoir, liquids and gases that are saturating the hydrocarbon-bearing horizon can be used to calculate development parameters for Korolev field, including production well locations, drilling schedules, and to facilitate both long-term and short-term forecasting for the purposes of optimizing the hydrocarbon recovery from the field.
The objective of this work is to assess the impact of adding 3 extra producing wells and find ways to optimize cumulative production with the least impact on the existing development plan by means of deeper understanding subsurface dynamic processes of the Korolev field. The challenge is a high degree of connectivity between wells in the productive formation throughout the field so that any change of production parameters affects the whole field&rsquos cumulative production. Trying to find a solution to optimum production of the reservoir forecast studies were carried out, the impact of each new well on development parameters was defined, sub-surface processes changes due to extra producers lead-in were explained and as a result of this thesis two optimization models were proposed, one of which will bring nearly 9.7 million barrels more oil.
31
Okabe, Clarissa Paiva. "Modelos de depleção para reservatorios de oleo espumo." [s.n.], 2006. http://repositorio.unicamp.br/jspui/handle/REPOSIP/264303.
Full textAbstract:
Orientador: Osvair Vidal TrevisanDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica e Instituto de Geociencias
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Resumo: Campos no Canadá e na Venezuela contendo reservatórios de óleo espumoso apresentaram recuperação primária da ordem de 10 a 15 % maior do que a estimada por simuladores numéricos Black-Oil. Além do alto fator de recuperação, foram observadas outras características não convencionais, como baixa razão gás-óleo e alta manutenção da pressão de reservatório. Esta discrepância entre o fator de recuperação estimado e o real é atribuída ao fato de que os simuladores Black-Oil não descrevem adequadamente o comportamento do gás em óleos espumosos. Nesta pesquisa são descritos e comparados três modelos numéricos de óleo espumoso propostos para o simulador pseudo-composicional CMG Stars. Estes modelos permitem descrever as etapas de evolução do gás, que compreendem desde a nucleação das bolhas de gás, o crescimento das bolhas, até a formação de uma fase conectada de gás, com reações cinéticas. Além disso, admite a presença de diferentes formas de gás ¿ gás em solução, gás preso, gás disperso e gás livre - nas fases gás e óleo. A mobilidade da fase gás é avaliada por uma composição de curvas de permeabilidade relativa ao gás. Com o estudo da influência de alguns parâmetros, algumas características típicas de reservatórios de óleo espumoso são explicadas, como a baixa produção de gás, o escoamento do gás na forma dispersa, a alta saturação crítica de gás e as altas razões de produção de óleo
Abstract: Fields in Canada and Venezuela, which contain foamy oil reservoirs, have exhibited a primary oil recovery on the order of 10 to 15 % greater than the recovery estimated by black-oil simulators. Besides the high oil recovery, other unusual characteristics have been observed, as low gas-oil ratio and high reservoir pressure maintenance. Such discrepancy between estimated and the actual oil recovery factor is attributed to the fact that black-oil simulators do not describe adequately gas behavior in foamy oils. In the present study, three numerical models of foamy oil behavior are described and compared using the pseudo-compositional simulator CMG Stars. These models allow describing the steps of gas evolution, since the nucleation of the gas bubbles, the bubble growing, until its connection to form a free phase, via kinetic reactions. The model admits the presence of different forms of gas ¿ solution gas, entrained gas, dispersed gas and free gas ¿ in the oil and gas phases. The mobility of the gas phase is evaluated by a composition of relative permeability curves. After the study on the influence of some parameters, some typical characteristics of the foamy oil reservoirs are explained, as the low gas production, the dispersed gas flow, the high critical gas saturation and the high oil production rates
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
32
Vollmer, Thees, and Ludger Frerichs. "Development of hydraulic tanks by multi-phase CFD simulation." Saechsische Landesbibliothek- Staats- und Universitaetsbibliothek Dresden, 2016. http://nbn-resolving.de/urn:nbn:de:bsz:14-qucosa-199968.
Full textAbstract:
Hydraulic tanks have a variety of different tasks. The have to store the volume of oil needed for asymmetric actors in the system as well as to supply the system with preconditioned oil. This includes the deaeration as air contamination is affecting the overall system performance. The separation of the air in the tank is being realized mainly by passive methods, improving the guidance of the air and oil flow. The use of CFD models to improve the design of hydraulic tank is recently often discussed. In this paper, a design method for hydraulic tanks using CFD is presented and discussed. First the different requirements on a hydraulic tank are described as well as the motivation changing the tank designs. Additionally, a quick overview on different calculation models for the behavior of air in oil as well as the capabilities of CFD to reproduce them is given. After this the methodology of tank design applying CFD is presented. The method is then used in an example.
33
Vasconcelos, David Dennyson Sousa. "Mitigação de incertezas através da integração com ajuste de histórico de produção e técnicas de amostragem." [s.n.], 2011. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265459.
Full textAbstract:
Orientadores: Denis José Schiozer, Célio MaschioDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: As incertezas geológicas influenciam diretamente a previsão de comportamento de reservatórios de petróleo, podendo, muitas vezes, tornar mais complexo o uso de ferramentas como simuladores de fluxo. A integração de técnicas de redução de incertezas e ajuste de histórico ganha um importante destaque neste processo, principalmente devido às limitações apresentadas pelas técnicas tradicionais de ajuste de histórico, sobretudo em campos com poucos dados de produção e maiores incertezas. O objetivo principal desse trabalho é obter um ajuste de histórico probabilístico a partir da redução das incertezas do modelo de reservatório. A proposta desse estudo é apresentar contribuições a uma metodologia existente, com o objetivo de possibilitar o tratamento de um elevado número de atributos incertos e aumentar a eficiência do processo. O método consiste em um procedimento dinâmico de calibração de propriedades do reservatório, utilizando dados observados e técnicas de amostragem. Os atributos considerados, discretizados em níveis de incertezas (com uma probabilidade associada), são submetidos a um processo de amostragem, com o método de Hipercubo Latino e, posteriormente combinados estatisticamente. Cada combinação entre níveis dos diferentes atributos resulta em um modelo de simulação e, após realizadas as simulações, novas probabilidades são estimadas, para cada nível, a partir de um procedimento que utiliza a diferença entre os dados observados e simulados, relativos a cada modelo. A qualidade do ajuste obtido pode ser avaliada a partir das curvas de incertezas, compostas por modelos representativos das probabilidades iniciais e finais de cada atributo e através dos indicadores propostos nesse trabalho, como variabilidade das probabilidades e afastamentos por poço. Os resultados obtidos indicam um método capaz de fornecer resultados confiáveis no processo de mitigação de incertezas, quando há dados de histórico disponíveis. O aumento na qualidade dos resultados com esse método, para as situações onde os atributos possuem mais níveis discretos que o convencional (normalmente são 3 níveis), depende do esforço computacional (em termos do número de simulações). Contudo, não há um aumento expressivo do número de simulações, como ocorre na técnica de árvore de derivação usada em trabalhos anteriores
Abstract: The geological uncertainties influence directly the prediction of reservoir behavior, making more complex the use of tools such as flow simulators. The integration between mitigation uncertainties techniques and history matching gains an important emphasis in this process, mainly due to the limitations presented by history matching traditional techniques, especially in areas with little observed data and greater uncertainties. The main objective of this work is to set a probabilistic history matching from the mitigation of reservoir uncertainty. The purpose of this study is to provide input to an existing methodology, in order to allow treatment of a large number of uncertain attributes and increase process efficiency. The method involves a dynamic procedure of global and local calibration of the geological model, using observed data and sampling techniques. The considered attributes, discretized into uncertainty levels (with an associated probability), are undergoing a sampling process, with Latin Hypercube method and then statistically combined. Each combination among levels of different attributes results in a complete simulation model, and after the simulations are performed, new probabilities are estimated for each level, from a procedure that uses the difference between observed and simulated data for each model. The quality of the history matching process can be evaluated from the uncertainty curves, composed of representative models of initial and final probabilities of each attribute, and using the indicators proposed in this work, as probabilities variability and the difference between observed and simulated data by well. The results obtained with this methodology indicate a tool capable of providing reliable results in the uncertainty mitigation process, when there is observed data available. The increase in quality of results with this method, for situations where the attributes has a number of discrete levels higher than the conventional technique (3 levels) depends on the computational effort (in terms of simulations number), but without the significant increase in the simulations number, as in the derivation tree technique used in previous works
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
34
Silva, Luciana dos Santos. "Integração de análise de incertezas e ajuste de histórico = aplicação em um caso complexo." [s.n.], 2011. http://repositorio.unicamp.br/jspui/handle/REPOSIP/262973.
Full textAbstract:
Orientador: Denis José SchiozerDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica
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Resumo: A grande quantidade de incertezas presente na modelagem de reservatórios gera riscos na previsão de comportamento de um campo de petróleo. Assim, torna-se imprescindível o ajuste de histórico, que é a calibração do modelo de simulação do reservatório com os dados dinâmicos observados, aproximando o modelo da realidade e gerando previsões mais confiáveis. Diversas metodologias surgiram para integrar a análise de incertezas com o ajuste de histórico, mas devido à complexidade do processo, algumas delas só se aplicam a casos simples. A proposta deste trabalho é aplicar os métodos desenvolvidos por Moura Filho (2006), Becerra (2007) e Maschio et al. (2010) em um caso complexo sintético, similar a um modelo real de um reservatório de petróleo e avaliá-los para propor melhorias na metodologia. A técnica consiste em utilizar as diferenças entre os dados de produção observados e os simulados para reduzir as incertezas do reservatório, calculando as probabilidades dos níveis dos parâmetros incertos. Para isso, os atributos incertos são discretizados em três níveis e é feita uma análise de sensibilidade para escolher os atributos críticos, os quais são combinados através da árvore de derivação para gerar os diferentes modelos de simulação. Com os dados históricos (medidos) e simulados destes modelos, é feita a redistribuição das probabilidades dos níveis utilizando e comparando dois métodos: o de Moura Filho e Becerra (Método 1) e o de Maschio et al. (Método 2). Os resultados deles não mostraram boa eficiência na redução das incertezas para o caso estudado, pois as curvas continuaram muito espalhadas com relação ao histórico. Sendo assim, foram criados o Método 3, utilizando as melhores práticas da formulação dos dois estudados com o objetivo de tornar a metodologia mais robusta para uso em casos reais, e o Método 4, que é uma reaplicação do Método 3 após a redefinição dos valores dos níveis dos atributos. Uma comparação dos resultados dos quatro métodos mostra a evolução da redução das incertezas. Além disso, consegue-se diminuir a dispersão dos modelos representativos, centralizando-os com relação ao histórico de produção, o que permite uma melhor previsão de produção e maior confiabilidade na análise de risco de projetos futuros
Abstract: The large amount of uncertainties in reservoir modeling increases petroleum production forecast risks. Therefore, the history matching, which refines the simulation model to closely reproduce production data, is a vital procedure once it approximates numerical models to reality providing reliable predictions. Many methodologies were developed to integrate uncertainty analysis and history matching in order to mitigate the reservoir uncertainties by using the observed data, but due to the process complexity, some of them are applicable only in simple cases. In this context, the present work aims to evaluate the application of existing methods, developed by Moura Filho (2006), Becerra (2007) and Maschio et al. (2010), in a synthetic complex model (i.e. similar to a real field) and propose new methods with some improvements to be applied in real cases of the petroleum industry. The main characteristic of these methods is the use of differences between observed and simulated data to recalculate the probabilities distribution of uncertain parameters with the purpose of reducing reservoir uncertainties. To apply the methods, the uncertainty attributes are discretized in three levels and a sensibility analysis is done to select the critical attributes, which are combined by a derivative tree generating different simulation models. With history and simulated data of these models, the redistribution of occurrence probabilities is made with different formulas: Moura Filho e Becerra (Method 1) and Maschio et al. (Method 2). These two methods are compared and their results don't show good efficiency in uncertainty reduction of the studied case, because the final curves remain widely scattered around history data. Then, two methods are proposed, Method 3, which combines the best practices of the two reviewed ones, making it robust to be used in real cases with a great number of wells and production functions to be adjusted such as water production and pressure. The second proposed one, Method 4, is a reapplication of the third method with a redefinition of attribute values in order to refine the results. A comparison of the results of the four methods shows an evolution in the uncertainty reduction. Besides that, there is a decrease in the dispersion of the representative curves, which are centralized around the history data, providing a better production forecast and greater reliability in risk analysis of future projects
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
35
Mercado, Sierra Diana Patricia 1981. "Modelo pseudocinético para a simulação numérica da combustão in-situ na escala da campo." [s.n.], 2015. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265773.
Full textAbstract:
Orientador: Osvair Vidal TrevisaTese (doutorado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: A combustão in-situ é um processo multiescala, multifísico que envolve simultaneamente o escoamento de fluidos no meio poroso, o equilíbrio de fases e a cinética das reações químicas. A simulação desse processo tem alcançado um elevado grau de desenvolvimento, no entanto, mecanismos básicos ainda são representados de maneira incompleta, impondo inúmeros desafios na modelagem. A dificuldade de modelar fenômenos relacionados com a combustão tem a ver com a representação do efeito da frente de combustão e a modelagem do consumo de combustível. Na combustão in-situ as reações químicas acontecem em uma zona delgada de menos de um metro de espessura, que é pequena quando comparada com a escala do reservatório de centenas ou milhares de metros. Na simulação na escala de campo, o uso de células de tamanho maior do que a zona de reação leva a erros na distribuição da temperatura. Consequentemente, a velocidade das reações não pode ser bem representada. De outro lado, os simuladores não permitem controlar a ocorrência das reações a partir da energia de ativação. Como resultado, o início das reações se torna independente da temperatura. O objetivo desta tese é desenvolver um modelo pseudocinético para a simulação numérica da combustão in-situ na escala de campo. Com o modelo pseudocinético pretende-se representar os fenômenos na zona de combustão, reduzindo o efeito do tamanho de célula. O trabalho foi desenvolvido em etapas. Primeiro foram estabelecidas as condições que o simulador deveria atender e definida a estratégia de abordagem, que foi a de desenvolver um modelo pseudocinético. Depois foi definida a metodologia de obtenção do modelo pseudocinético. Após o modelo pseudocinético concluído, este foi utilizado para a simulação de um campo de óleo pesado brasileiro submetido à combustão in-situ. O modelo pseudocinético proposto consiste em expressar a energia de ativação das reações em função da temperatura. Através do modelo, é possível restringir a ocorrência da reação de craqueamento, de modo que o início da formação do coque aconteça somente para temperaturas acima dos valores observados na zona de craqueamento. Note-se que neste cenário a quantidade de coque depositado pode ser modelada usando a reação de craqueamento, o que se constitui numa das principais contribuições do trabalho. O modelo permite manter a dependência da taxa de reação com a temperatura mediante o uso de valores de energia de ativação apropriados. Além disso, consegue-se reduzir o efeito da distribuição de temperatura mediante o controle da taxa de reação em função dos valores médios de temperatura observados nas células do modelo de simulação na escala de campo. Na simulação do piloto de combustão in-situ, o modelo pseudocinético foi obtido do ajuste progressivo dos parâmetros cinéticos das reações químicas, partindo da simulação do processo na escala de laboratório até a escala de campo. Os dados experimentais utilizados na simulação na escala de laboratório foram obtidos de um ensaio em tubo de combustão seca realizado no Laboratório de Métodos Térmicos de Recuperação do Departamento de Energia da UNICAMP. O fluido utilizado foi um óleo pesado de 15,3 °API proveniente da Bacia do Espírito Santo
Abstract: The in-situ combustion is a multi-scale, multi-physics process, involving fluid flow in porous media, thermodynamic equilibrium of the phases involved and chemical kinetics of reactions. The simulation of this process has achieved a high degree of development, however basic mechanisms are still represented incompletely, imposing numerous challenges in modeling. The issues in the combustion modeling are related with the representation of the combustion front effect and the fuel consumption modeling. Chemical reactions of the in-situ combustion process take place in a thin zone of less than a meter thick, which is small compared to the field scale of hundreds or thousands of meters. Numerical simulations at the field scale typically use grid blocks that are at least two orders of magnitude greater than that. Such divergence leads to improper representations of key aspects of the process, as the temperature distribution and the reaction kinetics. In accordance with that the reaction occurrence is not controlled by the activation energy in the simulation models. The major shortcome is on fuel deposition, a key issue in in-situ combustion, which will happen from the start, since the cracking reaction may proceed even at reservoir temperature. The objective of this thesis is to develop a new pseudokinetic model for field-scale simulation of in-situ combustion. With the pseudokinetic model meant to improve the representation of the combustion zone effects reducing the gridblock size effect. The work was carried out in stages. First establishes the conditions that the simulator should meet and defined the strategy to develop a pseudokinetic model. Then a methodology was defined for obtaining the pseudokinetic model. After the pseudokinetic model is completed, it is applied to the in-situ combustion modeling of a Brazilian heavy oil field. The models pursue the idea of making the activation energy a function of the grid block temperature. The model allows restricting the cracking reaction occurrence by the temperature, so that the beginning of the coke deposition occurs at temperatures greater than the temperature observed in the cracking zone. Note that in this scenario the cracking reaction can be used to represent the coke deposition, which constitutes one of the main contributions of this work. The model allows maintaining the dependence of reaction rate with temperature through the use of appropriate activation energy values. Furthermore, the model reduces the temperature distribution effect by controlling the reaction rate based on average temperature values observed in the field simulation model. In the simulation of the in-situ combustion pilot, the pseudokinetic model was obtained from the progressive tuning of the kinetic parameters of chemical reactions, based on the simulation of the process from the laboratory to field scale. The experimental data used in the laboratory scale simulation were obtained from a dry combustion tube test carried out at the Thermal Recovery Methods Laboratory of the Energy Department at UNICAMP. The fluid used was a 15.3 ° API heavy oil from the Espírito Santo Basin
Doutorado
Reservatórios e Gestão
Doutora em Ciências e Engenharia de Petróleo
36
Muñoz, Mazo Eduin Orlando 1976. "Análise do gerenciamento de água mediante o controle de poços injetores em reservatórios heterogêneos e fraturados." [s.n.], 2013. http://repositorio.unicamp.br/jspui/handle/REPOSIP/263723.
Full textAbstract:
Orientador: Denis José SchiozerTese (doutorado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: A injeção de água como método para auxiliar na recuperação de hidrocarbonetos e na manutenção da pressão em reservatórios tem sido aplicada de maneira crescente nas últimas décadas devido às suas características de eficiência, baixo custo e alta disponibilidade da água, o que faz com que este procedimento seja considerado com frequência na fase de desenvolvimento de campos de petróleo, como parte da estratégia inicial de produção. No entanto, volumes cada vez maiores de água produzida são reportados pelas companhias operadoras, com grandes implicações técnicas e econômicas para as mesmas. Esta situação pode, em alguns casos, fazer com que a água deixe de ser considerada como um recurso e passe a ser vista como um empecilho à produção. Outro problema associado à injeção de água em reservatórios é a perda de injetividade causada pela diminuição da permeabilidade na região vizinha aos poços injetores, decorrente do dano de formação. Portanto, implementar soluções ao problema da perda de injetividade e considerar o controle da água injetada e produzida na etapa de lançamento e otimização de estratégias de produção têm um impacto significativo no desempenho produtivo e financeiro de um projeto de exploração e produção (E&P), especialmente em reservatórios heterogêneos e fraturados, onde as propriedades petrofísicas trazem consequências importantes no escoamento dos fluidos de injeção e produção. Nesse trabalho é realizada uma análise da aplicação do processo de injeção com pressão de propagação de fratura (Injection with Fracture Propagation Pressure - IFPP) mediante a modelagem dos processos de perda de injetividade e propagação de fratura utilizando ferramentas de simulação de uso comercial. Posteriormente, uma metodologia para o gerenciamento de água baseada no controle dos volumes de injeção e produção de água é proposta e aplicada para casos de reservatório heterogêneo e naturalmente fraturado. Os resultados apontam que a injeção de água com propagação de fratura pode ser utilizada para remediar os efeitos nocivos da perda de injetividade, permitindo, em alguns casos, um aumento significativo da recuperação de óleo. Apontam também que a sua modelagem pode ser estudada como um problema de otimização de vazão, evidenciando a necessidade de inclusão do controle da injeção (otimização de vazão e determinação da data de fechamento do poço injetor) na fase de proposta e posterior otimização de estratégias de produção. Finalmente, mostram o efeito positivo do controle da injeção de água, aliado ao controle da produção, como mecanismo para o gerenciamento de água, possibilitando um melhor desempenho produtivo e financeiro de reservatórios heterogêneos e fraturados que utilizam a injeção de água como método de recuperação secundária
Abstract: Water injection as a method to assist hydrocarbon recovery and reservoir pressure maintenance has been applied increasingly in recent decades because of its characteristics of efficiency, low cost and high availability of water. This makes this procedure often considered in the development of oil fields as part of the initial production strategy. However, increasing volumes of produced water have been reported by the operating companies, with major technical and economic implications for them. This may cause the water to stop being regarded as a resource and to start to be seen as a constraint to the production. Another problem associated with water injection into the reservoir is the injectivity loss caused by the permeability decrease in the region adjacent to the injection wells due to the formation damage. Therefore, implementing solutions to the problem of injectivity loss and considering the control of injected and produced water in the proposal and optimization of production strategy stage have a significant impact on the productive and financial performance of exploration and production (E&P) projects. This happens in heterogeneous and fractured reservoirs, where the petrophysical properties have a significant impact on the flow of injection and production fluids. In this work is carried out an analysis of the application of the injection with fracture propagation pressure (IFPP) process by modeling injectivity loss and fracture propagation using commercial simulation tools. Subsequently, a methodology for water management based on control of injection volumes and water production is proposed and applied to cases of heterogeneous and naturally fractured reservoirs. The results show that water injection with fracture propagation can be used to remedy the harmful effects of injectivity loss allowing, in some cases, a significant increase in oil recovery. Also indicate that its modeling can be studied as a flow rate optimization problem, highlighting the need for the inclusion of the injection control (optimization of the injection rate and shutting time of the injection well) at the proposal and subsequent optimization stage of production strategies. Finally, show the positive effect of the control of water injection, coupled to the control of water production, as a mechanism for managing water, providing better productive and financial performance for heterogeneous and fractured reservoirs using water injection as a method of improved oil recovery
Doutorado
Reservatórios e Gestão
Doutor em Ciências e Engenharia de Petróleo
37
Magalhães, Tasso Cordeiro Benevides de. "Influencia de restrições operacionais na definição das estrategias de produção." [s.n.], 2005. http://repositorio.unicamp.br/jspui/handle/REPOSIP/263696.
Full textAbstract:
Orientador: Denis Jose SchiozerDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica e Instituto de Geociencias
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Resumo: Estratégias de produção para campos petrolíferos são escolhidas com o objetivo de obter o melhor desempenho possível dos reservatórios, considerando restrições físicas, operacionais e econômicas. Em vários trabalhos publicados sobre otimização das estratégias de produção considera-se apenas o reservatório, simplificando o processo de definição por não considerar as restrições operacionais das facilidades de produção. Entretanto, as restrições da unidade de processamento e dos equipamentos necessários para o escoamento do petróleo, não só influenciam a produtividade do reservatório e o retorno financeiro do empreendimento, como também podem causar impacto significativo na definição da estratégia de drenagem, influenciando a quantidade e localização de poços produtores e injetores e no gerenciamento das condições de operação. No presente trabalho, duas restrições operacionais são analisadas: a limitação da capacidade de tratamento de líquidos da unidade de produção e a quantidade gás no sistema de elevação, gas-lift. Foram otimizadas estratégias de produção com e sem tais restrições para alguns casos e várias diferenças puderam ser observadas nos valores de indicadores técnicos e financeiros, como valor presente líquido, produção e injeção de fluidos e a quantidade e posicionamento de poços produtores e injetores. Foi possível demonstrar a influência das restrições operacionais e que se as mesmas não forem incluídas no processo de otimização antes da definição da quantidade e posição dos poços, o desempenho do campo pode ser prejudicado
Abstract: Production strategies for petroleum fields are chosen with the objective of achieving the best possible performance of the reservoir, considering physical, operational and economical constraints. In many published papers regarding production strategy optimization, only the reservoir is considered, simplifying the analysis process by not considering the operational constraints of production facilities. However, the restrictions of a production unit and the necessary equipments to guarantee the flow of petroleum not only have influence on the reservoir production and on the enterprise profits, but can also cause significant impact on the definition of the drainage strategy, influencing the number and location of producer and injector wells and the operational conditions management. In this work, two operational constraints are analyzed: the limitation of the capacity for liquid treatment and the amount of available gas for gas-lift operation. Production strategies were optimized with and without these restrictions for some case-studies and many differences were noted in the value of technical and financial indicators, such as the net present value, the production and injection of fluids and the number and location of producer and injector wells. It was possible to demonstrate the influence of operational constraints and how their exclusion from the optimization process, before definition of the number and location of wells, can lead to a wrong assessment of the field performance
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
38
de, Carvalho Jacobina Andrade Deraldo. "Molecular Dynamics Study of Nano-confinement Effect on Hydrocarbons Fluid Phase Behavior and Composition in Organic Shale." Thesis, Virginia Tech, 2021. http://hdl.handle.net/10919/102912.
Full textAbstract:
The depletion of conventional oil reservoirs forced companies and consequently researchers to pursue alternatives such as resources that in the past were considered not economically viable, in consequence of the high depth, low porosity and permeability of the play zone. The exploration challenges were overcome mainly by the development of horizontal drilling and hydraulic fracturing. However, the extremely high temperatures and pressures, in association to a complex nanopore structure, in which reservoir fluids are now encountered, instigate further investigation of fluid phase behavior and composition, and challenge conventional macroscale reservoir simulation predictions. Moreover, the unusual high temperatures and pressures have increased the cost as well as the hazardous level for reservoir analyzes by lab experiments. Molecular Dynamics (MD) simulation of reservoirs can be a safe and inexpensive alternative tool to replicate reservoir pore and fluid conditions, as well as to monitor fluid behavior.
In this study, a MD simulation of nanoconfinement effect on hydrocarbon fluid phase and compositional behavior in organic shale rocks is presented. Chapter 1 reviews and discusses previous works on MD simulations of geological resources. With the knowledge acquired, a fully atomistic squared graphite pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that nano-confinement increases fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an alteration of oil in place (OIP) prediction by reservoir simulations, when nano-confinement effect is not considered.Master of Science
Petroleum sub products are present in the day to day life of almost any human. The list include gasoline, plastics, perfumes, medications, polyester for clothing. Petroleum is naturally encountered in the void space, known as pores, inside rocks at reservoirs thousands of feet underground. In the past, the pores of oil reservoirs in development were larger and interconnected, which facilitates its extraction and reserve predictions. Most of reservoirs being developed nowadays have pores in the nanoscale and with poor interconnection as well as higher reservoir temperatures and pressure. These "new conditions", instigates further investigation of fluid phase behavior and composition, and challenge macroscale reservoir simulation predictions. In this study, the effect of decrease in pore size, as well as higher temperature and pressure conditions, in fluid behavior and composition is studied. Chapter 1 reviews and discusses previous works on geological resources modeling and simulation. With the knowledge acquired, a fully squared shale pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that pores in the nanoscale region tend to increase fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an underestimation of reserves prediction by reservoir simulations, when the change in density is not considered.
39
Laboissière, Philipe 1980. "Injeção de vapor e nitrogenio na recuperação melhorada de oleo pesado." [s.n.], 2009. http://repositorio.unicamp.br/jspui/handle/REPOSIP/264286.
Full textAbstract:
Orientador: Osvair Vidal TrevisanDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica, Instituto de Geociencias
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Resumo: Métodos térmicos de recuperação, especialmente injeção de vapor, estão à frente da maioria dos projetos de recuperação de óleo pesado em terra. A injeção contínua e, mais recentemente, a injeção de vapor auxiliada por drenagem gravitacional permitem aumentar a recuperação. A razão do volume de vapor injetado por volume de óleo recuperado é um parâmetro decisivo na economicidade de projetos de inundação por vapor. No presente trabalho, um estudo experimental e um numérico na célula linear e um estudo numérico na célula SAGD foram desenvolvidos para entender melhor como a injeção de nitrogênio combinado com vapor contribui ao mecanismo de recuperação e para a possível redução em volume do vapor injetado. O estudo experimental foi conduzido num aparato de laboratório constituído de uma célula linear para a injeção contínua de vapor. Os estudos foram conduzidos em escala de laboratório com óleo pesado da bacia do Espírito Santo. As experiências na célula linear consistiram em injetar vapor ou vapor combinado com nitrogênio para recuperação de óleo. Nas experiências, vapor superaquecido a 170 ° C foi injetado a vazões entre 5 e 4,5 ml/min (equivalente em água fria) e nitrogênio injetado a vazões entre 50 e 180 ml/min. As principais conclusões da investigação (derivadas de cinco experimentos executados com consistentes condições operacionais) são: 1) a injeção de nitrogênio combinado com vapor acelera o início e o pico de produção de petróleo em comparação com a injeção de vapor puro; 2) a melhoria da razão vapor/óleo mostra o efeito benéfico da injeção de nitrogênio em substituição a uma fração substancial de vapor; 3) os volumes recuperados e as análises dos remanescentes apontam fatores de recuperação superiores a 45%. Pelos estudos numéricos, os resultados da modelagem da célula linear mostram frentes de vapor com comportamentos de acordo com os observados experimentalmente. No entanto, uma investigação mais aprofundada sobre o papel dos principais parâmetros utilizados para o ajuste de histórico é necessário. Os resultados simulados do SAGD - Wind Down mostram que 84% da produção do SAGD convencional podem ser recuperados com a metade de volume de vapor injetado, indicando uma redução da razão vapor/óleo de 42%.
Abstract: Thermal recovery methods, especially steam injection, are at the forefront of most onshore projects of heavy oil. The continuous injection and, recently, the steam assisted gravity drainage yield high recoveries. The ratio of the volume of steam injected per volume of produced oil is a decisive parameter in the success of steam flood projects. In the present work, an experimental and a numerical study were developed in the linear cell and a numerical study in the SAGD cell to better understand how the injection of nitrogen combined with steam contributes to the recovery mechanism, and to the possible reduction in volume of the injected steam. The experiment runs were conducted in a linear cell built for the continuous injection of steam. The studies were conducted at the lab scale using heavy oil originated from the Espírito Santo basin. The experiments in the linear cell consisted of continuously injecting steam or steam combined with nitrogen to recover oil. In the experiments, superheated steam at 170 ° C was injected at flow rates between 5 and 4,5 ml/min (cold-water equivalent) and nitrogen injected at rates between 50 and 180 ml/min. The main findings of the research (derived from five runs with consistent operating conditions) are as follows: 1) the injection of nitrogen combined with steam accelerates the start and peak of oil production compared to steam injection alone; 2) the improvement of steam oil ratio shows the beneficial effect of nitrogen injection in substitution to a substantial fraction of steam; 3) results indicates recovery factors exceeding 45%. On the numerical studies, the results from modelling of the linear cell show steam front behaviors in agreement to those observed experimentally. However, further investigation on the role of main parameters used for the history matching is necessary. The simulated results of SAGD - Wind Down shows that 84% of the production of conventional SAGD can be recovered with half of the volume of steam injected, indicating a reduction of steam oil ratio of 42%.
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
40
Costa, Odair Jose. "Estudo sobre injeção de agua acima da pressão de propagação de fratura." [s.n.], 2008. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265462.
Full textAbstract:
Orientador: Denis Jose SchiozerDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica, Instituto de Geociencias
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Resumo: A reinjeção de água produzida é um método muito utilizado para descarte de água e para suporte de pressão e energia do reservatório. Um problema comum da reinjeção é a perda de injetividade, que prejudica o processo e impede a operação em níveis ótimos de injeção. A perda de injetividade pode ser minimizada pela injeção de água com pressão acima da pressão de fratura do reservatório (IPF), que procura restaurar a capacidade de injeção. Para estudar este processo, um simulador geomecânico para modelagem da fratura é combinado com um simulador numérico de reservatórios para modelar e otimizar a condição de operação dos poços injetores. A fratura é representada por um poço horizontal virtual, de forma conjunta com formulações analíticas de declínio hiperbólico de permeabilidade, para representar o efeito do dano de formação. O objetivo do trabalho é estudar alguns casos para verificar em quais situações a IPF é conveniente. O modelo de simulação estudado foi um reservatório sintético com um arranjo de drenagem de cinco pontos invertido representando uma parte de um reservatório. Foram considerados três cenários, onde a variação foi o tipo de óleo empregado (leve, intermediário e pesado). Estes cenários foram elaborados com a finalidade de representar algumas possíveis situações que podem ocorrer em um campo real, onde a pressão de iniciação de fratura pode ser atingida pelo efeito da perda de injetividade ou devido às propriedades rocha-fluido. O desempenho da IPF foi avaliado utilizando o valor presente líquido (VPL) e produções acumuladas de óleo e água. Os resultados mostraram que o estudo da IPF pode ser considerado como parte de um processo de otimização de vazão de injeção, onde a fratura pode ou não ocorrer. Mostra-se que a IPF, em geral, antecipa a produção de óleo para os casos de viscosidade intermediária e alta, tornando o método bastante vantajoso, embora com maior produção de água. Já estudos com óleo leve indicam que a técnica só é interessante quando houver significativa perda de injetividade, onde a IPF serve como reparadora da injetividade
Abstract: Produced water re-injection is a valuable method of water disposal and pressure and energy support. A common water re-injection problem is the injectivity loss, which affects negatively the process and restrains optimal water injection rates. The injectivity loss can be minimized by water injection with fracture propagation pressure (IFPP), which aims to restore injection capacity. To study this process, a geo-mechanical simulator for fracture modeling combined with a commercial reservoir simulation package is used to model and to optimize the operation condition of water injection wells. The fracture is represented by a virtual horizontal well and analytical formulations of hyperbolic decline of permeability are used to represent the effect of formation damage. This work aims the study of some cases to verify in which situations the IFPP is convenient. The simulation model studied is a synthetic reservoir with a five-spot pattern, representing a region of a reservoir. Three scenarios are considered, with different oil types (light, intermediate and heavy). These scenarios are proposed to reproduce some possible situations, where fracture pressure can be reached by the effect of the injectivity loss or due to rock and fluid characteristics. The behavior of the IFPP is evaluated using the net present value (NPV) and cumulative oil and water productions. The results showed that the IFPP study can be considered as part of an optimization problem of injection flow, where the fracture may occur. It is shown that IFPP, in general, presents advantages for intermediate and high viscosity oil because it anticipates oil production. Studies with light oil indicate that the technique is only interesting when there is significant injectivity loss, where IFPP is desirable for injectivity restoration
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
41
Sanches, Kemily Keiko Miyaji 1986. "Análise de fatores que influenciam a recuperação de petróleo por injeção de polímero." [s.n.], 2014. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265800.
Full textAbstract:
Orientador: Rosângela Barros Zanoni Lopes MorenoDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: A grande dependência da sociedade por produtos feitos a partir do petróleo e seus derivados, bem como seu preço elevado, motivam o estudo e o desenvolvimento de métodos de recuperação avançada. Estes métodos viabilizam explotar o maior volume possível de petróleo de forma contínua e por mais tempo. Os métodos de recuperação avançada de petróleo podem ser classificados como miscíveis, térmicos e químicos. A injeção de polímero é um método químico, onde polímero é adicionado à água de injeção com o objetivo de aumentar sua viscosidade e, consequentemente, reduzir a razão de mobilidade e aumentar a eficiência de varrido. Entretanto, este processo não é aplicável a qualquer caso, sendo necessário o uso de métodos de seleção e descarte, além de uma atenção especial para que suas propriedades não sejam degradadas durante a aplicação do método. Este trabalho apresenta uma análise da recuperação de petróleo por injeção de água alternada com banco de polímero (WAP) em comparação com a injeção contínua de água (WF) através da utilização de um simulador comercial. Além disso, foram analisadas variações em relação ao volume de solução polimérica injetada, ao instante de início da injeção de polímero, às curvas de permeabilidade relativa, à viscosidade da solução polimérica, bem como, às saturações de óleo residual e inicial de água, a fim de verificar os efeitos na recuperação de óleo. O estudo de modelos de reservatório em escala laboratorial é realizado como uma primeira e simplificada análise de seu potencial de recuperação de petróleo. A escala laboratorial permite uma análise mais detalhada do comportamento dos fluidos dentro do modelo, além de admitir a realização de testes para posterior aplicação no modelo real. Assim, foi realizado o estudo em escala laboratorial, para um modelo homogêneo, três modelos com heterogeneidades horizontais e dois modelos com heterogeneidades verticais. Posteriormente, o modelo homogêneo foi utilizado para uma análise de aumento de escala, a fim de verificar se os modelos estão bem representados. E em seguida foi realizada uma análise econômica. Entre os resultados observados, pode-se mencionar que: quanto maiores os bancos de solução polimérica injetados, maiores foram os volumes de óleo produzido, porém com menores volumes de óleo produzido por massa de polímero; a antecipação na injeção da solução polimérica gera uma antecipação na produção; o uso de soluções com polímero mais viscosas reduz o valor da razão de mobilidade e aumenta a produção de óleo, entretanto demanda pressões de injeção mais elevadas; quanto menor é o valor da permeabilidade relativa à água na saturação de óleo residual, maior é o ganho de produção de óleo, uma vez que o valor da razão de mobilidade é menor; quanto menores forem as saturações de óleo residual e de água inicial, maior é a recuperação, uma vez que a quantidade de óleo móvel é maior. Os melhores resultados em relação à recuperação de óleo foram obtidos pelos modelos heterogêneos verticais em comparação com o modelo homogêneo e heterogêneos horizontais. E o modelo em escala de campo demonstrou estar muito bem representado, sem divergência de valores em relação ao modelo em escala laboratorial
Abstract: The significant dependence of society for products made from petroleum and its derivatives, as well as its high price, motivate the study and the development of advanced recovery methods. This methods enable the exploitation of the largest possible volume of oil continuously and longer. The enhanced oil recovery methods can be classified as miscible, thermal and chemical methods. The polymer injection is a chemical process, where polymer is added to the injection water aiming increase its viscosity, consequently reducing the water-oil mobility ratio and increasing the sweep efficiency. However, this process does not apply to any case, requiring the use of screening criteria, and particular attention to that their properties are not degraded during the application of the recovery. This paper presents an analysis of oil recovery by water injection alternated with a polymer slug (WAP) compared to the continuous water flooding (WF) with the use of a commercial simulator. Moreover, variations in the slug size of the injected polymer solution, injection starting time of the polymer slug, relative permeability curves, polymer viscosity, residual oil and initial water saturation were carried out to determine the effects on oil recovery. The study of reservoir models in laboratory scale is made on a first and simplified analysis of their oil recovery potential. The laboratory scale allows a more detailed discussion of fluid behavior inside the model, and admits to testing for further application in the real model. Thus, the study was conducted in laboratory scale, for one homogeneous model, three models with horizontal heterogeneities and two models with vertical heterogeneities. Subsequently, the homogeneous model was used for analysis of size increase in order to ascertain whether templates are well represented. And then an economic analysis was performed. Among the results, it can be mentioned that: larger slugs of polymer solution lead to larger volumes of produced oil, however with decreasing amounts of produced oil per mass of polymer; the anticipation on the injection of the polymer solution leads to an anticipation in oil production; the use of higher viscous polymer solutions lead to lower value of the mobility ratio and higher oil production, however requires higher injection pressures; lower values of relative permeability to water at residual oil saturation lead to large difference on relative gain of oil production once the final mobility ratio is lower; lower residual oil and initial water saturation leads to a high oil recovery, mainly as consequence of the greater amount of mobile oil. The best results for oil recovery were obtained by vertical heterogeneous models compared to the homogeneous model and horizontal heterogeneous. And the model in field scale proved to be well represented, without deviation values relative to the model in laboratory scale
Mestrado
Reservatórios e Gestão
Mestra em Ciências e Engenharia de Petróleo
42
Santana, Gustavo Menezes 1986. "Efeitos de histerese de permeabilidade relativa em reservatórios de óleo leve com injeção WAG-CO2." [s.n.], 2014. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265848.
Full textAbstract:
Orientadores: Denis José Schiozer, Eliana Luci LigeroDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
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Resumo: Os reservatórios do pré-sal brasileiro apresentam grandes volumes de óleo leve com quantidade significativa de CO2 dissolvido. O CO2 produzido no pré-sal pode ser utilizado como gás de injeção no método especial de recuperação de injeção alternada de água e gás (WAG). Neste trabalho, a injeção WAG-CO2 miscível é empregada na recuperação de um óleo leve com teor de cerca de 8% molar de CO2 em condições análogas às do pré-sal de alta pressão e baixa temperatura, onde fenômenos físicos inerentes à injeção WAG-CO2 são incorporados aos modelos de simulação de reservatórios através dos modelos de histerese da permeabilidade relativa, tal como o modelo trifásico de Larsen e Skauge (1998). Este trabalho tem como foco o estudo dos efeitos da modelagem da histerese de permeabilidade relativa em simulações de injeção WAG-CO2 miscível. Dois modelos sintéticos de reservatório com óleo leve e com diferentes graus de heterogeneidade são estudados. Os modelos de simulações empregam a formulação composicional por ser mais apropriada em casos de injeção de gás miscível em óleo leve. A histerese causa redução da permeabilidade relativa aos fluidos, o que pode gerar dois efeitos: o aumento da eficiência local de varrido de óleo e a perda de injetividade. O primeiro efeito contribui para o aumento da recuperação de óleo, enquanto a perda de injetividade, dependendo das condições operacionais dos poços, resulta na redução da quantidade de fluidos injetada, prejudicando a recuperação. O predomínio de um desses dois efeitos faz com que a implementação dos efeitos da histerese de permeabilidade relativa nos modelos de simulação com injeção WAG resulte em recuperações finais de óleo diferentes das obtidas nos casos em que a histerese não é considerada, atingindo-se valores até 8% maior ou menor conforme efeito predominante e condições operacionais utilizadas
Abstract: The Brazilian pre-salt reservoirs present large volumes of light oil with a significant amount of dissolved CO2. It is intended to use CO2 produced in the pre-salt as an injection gas on the enhanced oil recovery method of water-alternating-gas (WAG) injection. In this work, the miscible WAG-CO2 injection is used in light oil recovery with an amount of 8% molar CO2 in similar conditions to pre-salt with high pressure e low temperature where physical phenomena involving WAG-CO2 injection applied to a reservoir of light oil with dissolved CO2 are built into the reservoir simulation models through the hysteresis of relative permeability models, as the Larsen and Skauge (1998) model. This work focuses on the study of the effects of modeling the hysteresis of relative permeability in simulation of miscible WAG-CO2 injection. Two synthetic reservoir models with light oil and different heterogeneities are studied. The simulation models employ the compositional formulation because it is more appropriate in cases of miscible gas injection in light oil. The hysteresis causes a reduction of the relative permeability of the fluid, which can cause two effects: increased local oil swept efficiency and the loss of injectivity. The first effect contributes to increase the oil recovery, while the loss of injectivity, depending on the operating conditions of the wells, results in a reduction of the amount of injected fluids, reducing the recovery. The predominance of one of these two effects makes the implementation of the effects of hysteresis of the relative permeability in simulation models with WAG injection exhibit different results compared to those models without hysteresis, reaching values up to 8% higher or lower according to the predominant effect and operational conditions used
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
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Aasum, Yngve. "Effective properties of reservoir simulator grid blocks /." Access abstract and link to full text, 1992. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9300177.
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Hernandez, Ramos Juan Carlos. "Sensitivity of reservoir simulations to uncertainties in viscosity." Thesis, Imperial College London, 2001. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.369224.
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Hwessa, Mahmod Mjahead. "Numerical Simulation Study: Air Injection Technique for Improved Oil Recovery (IOR) from Light Oil Reservoirs." Thesis, University of Bath, 2009. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.508714.
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Syahrial, Ego. "Development of a novel compositional simulation approach to model recovery from oil reservoirs." Thesis, Imperial College London, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.265942.
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Bentaher, Abdul Hafid R. "Air injection technique for IOR from light oil reservoirs : kinetics and simulation studies." Thesis, University of Bath, 2002. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.250844.
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Parafita, Jofranya Wendyana Alves. "An?lise param?trica do m?todo de inje??o alternada de ?gua e CO2(WAG) em reservat?rios de petr?leo." Universidade Federal do Rio Grande do Norte, 2014. http://repositorio.ufrn.br:8080/jspui/handle/123456789/12998.
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Previous issue date: 2014-03-06After the decline of production from natural energy of the reservoir, the methods of enhanced oil recovery, which methods result from the application of special processes such as chemical injection, miscible gases, thermal and others can be applied. The advanced recovery method with alternating - CO2 injection WAG uses the injection of water and gas, normally miscible that will come in contact with the stock oil. In Brazil with the discovery of pre-salt layer that gas gained prominence. The amount of CO2 present in the oil produced in the pre-salt layer, as well as some reservoirs is one of the challenges to be overcome in relation to sustainable production once this gas needs to be processed in some way. Many targets for CO2 are proposed by researchers to describe some alternatives to the use of CO2 gas produced such as enhanced recovery, storage depleted fields, salt caverns storage and marketing of CO2 even in plants. The largest oil discoveries in Brazil have recently been made by Petrobras in the pre -salt layer located between the states of Santa Catarina and Esp?rito Santo, where he met large volumes of light oil with a density of approximately 28 ? API, low acidity and low sulfur content. This oil that has a large amount of dissolved CO2 and thus a pioneering solution for the fate of this gas comes with an advanced recovery. The objective of this research is to analyze which parameters had the greatest influence on the enhanced recovery process. The simulations were performed using the "GEM" module of the Computer Modelling Group, with the aim of studying the advanced recovery method in question. For this work, semi - synthetic models were used with reservoir and fluid data that can be extrapolated to practical situations in the Brazilian Northeast. The results showed the influence of the alternating injection of water and gas on the recovery factor and flow rate of oil production process, when compared to primary recovery and continuous water injection or continuous gas injection
O m?todo de recupera??o avan?ada com inje??o alternada WAG-CO2 utiliza da inje??o de ?gua e g?s, g?s esse normalmente misc?vel que vai entrar em contato com o banco de ?leo. No Brasil com a descoberta da camada pr?-sal esse g?s ganhou destaque. A quantidade de CO2 presente no ?leo produzido na camada pr?-sal, assim como acontece em alguns reservat?rios ? um dos desafios a serem vencidos com rela??o ? produ??o sustent?vel uma vez que esse g?s precisa ser processado de alguma maneira. Muitos os destinos para o CO2 s?o propostos por estudiosos, que descrevem algumas alternativas para uso do g?s CO2 produzido, tais como, recupera??o avan?ada, armazenamento em campos depletados, armazenamento em cavernas de sal e ainda comercializa??o do CO2 em plantas. As maiores descobertas de petr?leo, no Brasil, foram feitas recentemente pela Petrobras na camada pr?-sal localizada entre os estados de Santa Catarina e Esp?rito Santo, onde se encontrou grandes volumes de ?leo leve com uma densidade em torno de 28? API, baixa acidez e baixo teor de enxofre. ?leo esse que possui uma grande quantidade de CO2 dissolvido e assim uma solu??o pioneira para o destino desse g?s vem sendo a recupera??o avan?ada. O objetivo dessa pesquisa ? analisar quais os par?metros que tiveram maior influ?ncia no processo de recupera??o avan?ada. As simula??es foram realizadas utilizando o m?dulo GEM da Computer Modelling Group, com o objetivo de realizar estudos do m?todo de recupera??o avan?ada em quest?o. Para a realiza??o deste trabalho, modelos semi-sint?ticos foram utilizados com dados de reservat?rio e fluidos que podem ser extrapolados para situa??es pr?ticas do Nordeste brasileiro. Os resultados mostraram a influ?ncia do processo de inje??o alternada de ?gua e g?s sobre o fator de recupera??o e vaz?o de produ??o de ?leo, quando comparados ? recupera??o prim?ria e inje??o cont?nua de ?gua ou inje??o cont?nua de g?s
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Gurgel, Ant?nio Robson. "Estudo param?trico da inje??o de vapor em reservat?rios delgados." Universidade Federal do Rio Grande do Norte, 2009. http://repositorio.ufrn.br:8080/jspui/handle/123456789/12899.
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Previous issue date: 2009-07-30Petr?leo Brasileiro SA - PETROBRAS
Exploration of heavy oil reservoirs is increasing every year in worldwide, because the discovery of light oil reservoirs is becoming increasingly rare. This fact has stimulated the research with the purpose of becoming viable, technically and economically, the exploration of such oil reserves. In Brazil, in special in the Northeast region, there is a large amount of heavy oil reservoir, where the recovery by the so called secondary methods Water injection or gas injection is inefficient or even impracticable in some reservoirs with high viscosity oils (heavy oils). In this scenario, steam injection appears as an interesting alternative for recover of these kinds of oil reservoirs. Its main mechanism consists of oil viscosity reduction through steam injection, increasing reservoir temperature. This work presents a parametric simulation study of some operational and reservoir variables that had influence on oil recovery in thin reservoirs typically found in Brazilian Northeast Basins, that use the steam injection as improved oil recovery method. To carry out simulations, it was used the commercial software STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) from CMG (Computer Modeling Group) version 2007.11. Reservoirs variables studied were horizontal permeability, vertical and horizontal permeability ratio, water zone and pay zone thickness ratio, pay zone thickness and thermal conductivity of the rock. Whereas, operational parameters studied were distance between wells and steam injection rate. Results showed that reservoir variables that had more influence on oil recovery were horizontal permeability and water zone and pay zone thickness ratio. In relation to operational variables, results showed that short distances between wells and low steam injection rates improved oil recovery
A cada ano tem ocorrido cada vez mais a explora??o de reservas de ?leo pesado em diversas regi?es do mundo. Isto tem sido feito porque ? cada vez mais rara a exist?ncia de jazidas petrol?feras de ?leos leves. Este fato tem impulsionado in?meras pesquisas em dire??o a tornar vi?vel, do ponto de vista operacional e econ?mico, a explora??o de tais reservas de ?leo. No Brasil, em especial na regi?o Nordeste, existe uma grande quantidade de reservat?rios de ?leos pesados, onde a recupera??o pelos m?todos ditos secund?rios inje??o de ?gua e gases mostram-se ineficientes ou at? invi?veis em alguns reservat?rios que apresentam ?leos de elevada viscosidade. Neste cen?rio, a inje??o de vapor surge como uma alternativa bastante interessante na recupera??o do ?leo desses tipos de reservat?rios. Seu principal mecanismo consiste na redu??o da viscosidade do ?leo por meio da inje??o de um fluido aquecido, no caso, vapor de ?gua, aumentando a temperatura do reservat?rio. Este trabalho apresenta um estudo param?trico das vari?veis de reservat?rio e operacionais que influenciam no fator de recupera??o de ?leo ao longo da vida produtiva do reservat?rio em reservat?rios delgados tipicamente encontrados em Bacias do Nordeste brasileiro, que utilizam a inje??o de vapor como m?todo avan?ado de recupera??o. O estudo foi conduzido atrav?s de simula??o num?rica, utilizando o programa STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) do grupo CMG (Computer Modelling Group) vers?o 2007.11. As vari?veis de reservat?rio compreenderam a permeabilidade horizontal, a raz?o entre a permeabilidade vertical e horizontal, a raz?o entre a zona de ?gua e a de ?leo, a espessura da zona produtora de ?leo e a condutividade t?rmica da rocha. Enquanto que os par?metros operacionais estudados foram a dist?ncia entre po?os e a vaz?o de inje??o de vapor. Os resultados obtidos mostraram que as vari?veis de reservat?rios que mais influenciaram no fator de recupera??o foram a permeabilidade horizontal e a raz?o entre a zona de ?gua e de ?leo. Com rela??o ?s vari?veis operacionais, menores dist?ncias entre po?os e vaz?es de inje??o melhoram o fator de recupera??o durante a vida produtiva do reservat?rio
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Aldejain, Abdulaziz A. "Implementation of a dual porosity model in a chemical flooding simulator /." Digital version accessible at:, 1999. http://wwwlib.umi.com/cr/utexas/main.
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