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Robelius, Fredrik. "Giant Oil Fields - The Highway to Oil : Giant Oil Fields and their Importance for Future Oil Production." Doctoral thesis, Uppsala University, Department of Nuclear and Particle Physics, 2007. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-7625.
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Since the 1950s, oil has been the dominant source of energy in the world. The cheap supply of oil has been the engine for economic growth in the western world. Since future oil demand is expected to increase, the question to what extent future production will be available is important.
The belief in a soon peak production of oil is fueled by increasing oil prices. However, the reliability of the oil price as a single parameter can be questioned, as earlier times of high prices have occurred without having anything to do with a lack of oil. Instead, giant oil fields, the largest oil fields in the world, can be used as a parameter.
A giant oil field contains at least 500 million barrels of recoverable oil. Only 507, or 1 % of the total number of fields, are giants. Their contribution is striking: over 60 % of the 2005 production and about 65 % of the global ultimate recoverable reserve (URR).
However, giant fields are something of the past since a majority of the largest giant fields are over 50 years old and the discovery trend of less giant fields with smaller volumes is clear. A large number of the largest giant fields are found in the countries surrounding the Persian Gulf.
The domination of giant fields in global oil production confirms a concept where they govern future production. A model, based on past annual production and URR, has been developed to forecast future production from giant fields. The results, in combination with forecasts on new field developments, heavy oil and oil sand, are used to predict future oil production.
In all scenarios, peak oil occurs at about the same time as the giant fields peak. The worst-case scenario sees a peak in 2008 and the best-case scenario, following a 1.4 % demand growth, peaks in 2018.
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Long, Keith Richard. "Estimating the number and sizes of undiscovered oil and gas pools." Diss., The University of Arizona, 1988. http://hdl.handle.net/10150/184516.
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This study introduces a new specification of oil and gas exploration as a sampling process, in order to estimate the number and sizes of undiscovered oil and gas pools by statistical inference from discovered pools as a sample. Oil and gas exploration is quite unlike drawing samples at random in that actual sampling is size-biased, subject to truncation of uneconomic pools, and to censorship of discovered pool sizes. The method of estimating the number and sizes of undiscovered pools proposed in this study specifically accounts for these non-random components of exploration as a sampling process, and can be easily implemented using the Expectation-Maximization algorithm. The method allows for choices between single and multiple point truncation of uneconomic pool sizes, and generalizes quite easily to the bivariate case necessary to analyze plays with pools that contain oil with associated gas. Its usefulness is enhanced by the introduction of powerful tests of fit of the lognormal distribution to the distribution of discovered pool sizes, and of meaningful measures of the uncertainty of estimates of the number and sizes of undiscovered pools. Application of the method to oil and gas plays in the San Juan basin of northwest New Mexico show that it yields quite reasonable and useful results. The method, when applied to data analyzed using other methods of estimating the number and sizes of undiscovered pools, confirms that failure to account for truncation of uneconomic pools will result in an overestimate of the average size of pools in a play. By avoiding this, and other, problems, the proposed estimation procedure should lead to better assessments of a play's potential for future discoveries of economically recoverable oil and gas.
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Hülse, Eduardo Otte. "Robust production optimization of gas-lifted oil fields." reponame:Repositório Institucional da UFSC, 2015. https://repositorio.ufsc.br/xmlui/handle/123456789/158823.
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Dissertação (mestrado) - Universidade Federal de Santa Catarina, Centro Tecnológico, Programa de Pós-Graduação em Engenharia de Automação e Sistemas, Florianópolis, 2015.Made available in DSpace on 2016-02-09T03:08:04Z (GMT). No. of bitstreams: 1 337432.pdf: 1873519 bytes, checksum: 40fce035101e01804e1bc88f7e1ea3a5 (MD5) Previous issue date: 2015
Com a crescente demanda por energia fóssil as operadoras petrolíferas têm buscado determinar planos operacionais que otimizam a produção dos campos em operação para satisfazer a demanda do mercado e reduzir os custos operacionais. Neste contexto, a pesquisa operacional tem se mostrado uma importante ferramenta para determinação dos planos de produção de curto prazo para campos de petróleo complexos. Alguns trabalhos já desenvolveram estratégias para a otimização integrada da produção que visam auxiliar engenheiros de produção e operadores a atingir condições de operação ótimas. Estes avanços científicos atestam o potencial da área de otimização integrada da produção de campos, justificando a busca por estratégias de otimização global e integradas de ativos. Contudo, a incerteza dos parâmetros que caracterizam o reservatório, os poços, fluidos e os diversos processos de produção não vem sendo considerada pelos modelos e algoritmos de otimização da produção diária. Considerando os modelos de produção de curto prazo, estas incertezas podem ser atribuídas a erros de medição , comportamento oscilatório dos sistemas, modelos imprecisos, entre outros. A influência da incerteza dos parâmetros em problemas de otimização tem, desde tempos, sido foco da comunidade de programação matemática. E já foi verificado que soluções de problemas de otimização podem apresentar significativa sensibilidade à pertubações nos parâmetros do dado problema, podendo levar a soluções não factíveis, subótimas ou ambas. Assim, buscando tornar as abordagens de otimização existentes mais confiáveis e robustas às incertezas intrínsecas dos sistemas de produção, esta dissertação investiga a modelagem e tratamento de incertezas na otimização diária da produção e propõe formulações em programação matemática para otimização robusta da produção de poços operados por gas-lift. As formulações representam curvas amostradas através de dados simulados ou medidos que refletem as incertezas dos sistemas de produção. Estas representações levam a formulações robustas em programação matemática inteira mista obtidas pela aproximação das curvas de produção através de linearização por partes. Além disso, este trabalho apresenta os resultados de uma analise computacional comparativa da aplicação da formulação robusta e da formulação nominal a um campo de petróleo em ambiente de simulação, porém considerando simuladores multifásicos amplamente empregados pela indústria do petróleo e gás, que representam a fenomenologia muito próximo da realidade. O primeiro capítulo apresenta a problemática em que estão envolvidos os desenvolvimentos realizados nesta dissertação e um resumo dos capítulos subsequentes. No segundo capítulo alguns conceitos fundamentais são apresentados para a compreensão do trabalho desenvolvido. Este capítulo é dividido em três partes. A primeira parte inicia apresentando brevemente a indústria de petróleo e gás com uma perspectiva histórica, econômica e dos processos envolvidos. Na sequência são expostos conceitos básicos de engenharia de petróleo necessários para o entendimento do sistema de produção utilizado ao longo a dissertação  i.e. gas-lift. Finalmente, o problema de otimização da produção é situado dentro do problema maior, que é o gerenciamento completo das operações de um campo de petróleo, seguido de uma revisão da literatura no que se refere a abordagens clássicas para otimização da produção de campos operados por gas-lift. A segunda parte é uma descrição compacta sobre modelagem de problemas de otimização utilizando programação matemática e na menção dos métodos de solução deste tipo de problema utilizados na parte experimental desta dissertação. A terceira parte começa com uma revisão sobre incerteza em problemas de otimização e sobre as decisões de modelagem enfrentadas quando na presença de problemas de otimização incertos. Na sequência o paradigma de otimização robusta é introduzido e é apresentada uma compilação de alguns dos principais resultados da área de otimização robusta linear. Além disso, ao fim, alguns pontos específicos da teoria de otimização robusta são apresentados pela suas relevâncias para o desenvolvimento da teoria dos capítulos seguintes. O terceiro capítulo inicia com uma discussão sobre as origens das incertezas nos modelos de produção para então prover uma revisão bibliográfica dos poucos trabalhos que mencionam ou lidam com incerteza em sistemas de produção. Na sequência, a incerteza é examinada na perspectiva do problema de otimização. Um sistema simples é usado para exemplificar a metodologia de otimização robusta desenvolvida nesta dissertação. O quarto capítulo apresenta dois problemas padrões de otimização da produção, um contendo poços satélites e outro com poços e completação submarina. Para ambos uma formulação em programação linear inteira mista é descrita considerando valores nominais para todos os parâmetros. Então, para cada problema uma reformulação robusta é implementada considerando incerteza nas curvas de produção do poço. A metodologia utilizada para o primeiro problema é a mesma detalhada no capítulo três, e para o segundo uma extensão da metodologia é proposta para poder lidar com restrições de igualdade incertas. No quinto capítulo são apresentados resultados experimentais de um problema de otimização da produção de um campo com poços satélites. Os resultados obtidos com otimização clássica (nominal) e com otimização robusta são então comparados em um campo de produção sintético instanciado em um simulador multifásico comercial. A solução robusta se mostrou indicada para cenários de operação mais críticos onde factibilidade e segurança são prioridade. No capítulo final uma análise dos resultados obtidos na dissertação é feita sob a perspectiva do possível emprego das técnicas desenvolvidas na indústria de óleo e gás. Apesar de à primeira vista os resultados serem conservadores e de sua utilização parecer limitada, existe potencial para a metodologia ser empregada no caso de situações que priorizam segurança. Além disso a metodologia aqui desenvolvida pode servir como ponto inicial para pesquisas e desenvolvimentos futuros. Uma breve descrição de possíveis trabalhos futuros é feita ao final deste capítulo. O apêndice traz a descrição de algoritmos de amostragem de curvas côncavas desenvolvidos para os experimentos numéricos realizados na dissertação.
Abstract : Managing production of complex oil fields with multiple wells and coupled constraints remains a challenge for oil and gas operators. Some technical works developed strategies for integrated production optimization to assist production engineers in reaching best operating conditions. However, these works have neglected the uncertainties in the well-performance curves and production processes, which may have a significant impact on the operating practices. The uncertainties may be attributed to measurement errors, oscillating behavior, and model inaccuracy, among others. To this end, this dissertation investigates how uncertainty might be considered in daily production optimization and proposes formulations in mathematical programming for robust production optimization of gas-lifted oil fields. The formulations represent system-measured and simulated sample curves that reflect the underlying uncertainties of the production system. The representations lead to robust mixed-integer linear programming formulations obtained from piecewise-linear approximation of the production functions. Further, this work presents results from a computational analysis of the application of the robust and nominal formulations to a representative oil fields available in simulation software.
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Galvão, Raphael de Albuquerque. "Optimal regulation of oil fields under asymmetric information." reponame:Repositório Institucional do FGV, 2012. http://hdl.handle.net/10438/9908.
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This work considers a relationship between a regulator and an oil company. There are many uncertainties inherent in this relationship and we focus on the e ects of asymmetric information. We characterize the optimal regulation under asymmetric information, when the regulator must design a mechanism that induces truthful revelation about the rm's private information. We show that, when the rm cannot commit not to quit the relationship, the regulator may not be able to implement the optimal rst-best regulatory outcome. In this case, the regulator cannot achieve the optimal risk-sharing with the rm. We also provide an example, in which we show that the Spence-Mirrlees condition (SMC) may not hold. As it turs out, this is a natural result in our model rather than an imposition.
Neste trabalho é analisada a relação entre um regulador e uma empresa petrolífera. Há várias incertezas inerentes à essa relação e o trabalho se concentra nos efeitos da assimetria de informação. Fazemos a caracterização da regulação ótima sob informação assimétrica, quando o regulador deve desenhar um mecanismo que induz a firma a revelar corretamente sua informação privada. No caso em que a rma não pode se comprometer a não romper o acordo, mostramos que o regulador pode não implementar o resultado ótimo que é obtido sob informação completa. Nesse caso, o regulador não consegue compartilhar os riscos com a firma de forma ótima. Por fim, é apresentado um exemplo, em que mostramos que a condição de Spence-Mirrlees (SMC) pode não valer. Esse resultado aparece de forma natural no modelo.
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El-Feghi, Farag Abdulrazzak. "Miscible flooding in correlated random fields." Thesis, Heriot-Watt University, 1992. http://hdl.handle.net/10399/1506.
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Al-Hadithi, Nazar Omar Mukhalif. "Sedimentation and genesis of the Late Cretaceous Khasib and Tanuma Formations, East Baghdad Field, Iraq." Thesis, University of Reading, 1990. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.240805.
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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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Watson, Roseleen S. "The diagenesis of tertiary sands from the Forth and Balmoral fields, Northern North Sea." Thesis, University of Aberdeen, 1993. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.385559.
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The Palaeocene and Eocene Forth Field is located in Quad. 9, Block 23/b, adjacent to the East Shetland Platform. The Fourth reservoir consists of a series of massive well sorted, medium to fine grained, turbidite sands which contain biodegraded oil and gas. The textural homogeneity of the Forth sands suggests that sedimentary facies was not a major diagenetic control. The timing of oil migration and the periodicity of oil leakage controlled the relative paragenesis in different sand units. Pervasive ferroan and non ferroan calcite cemented sand horizons dominate the Forth paragenetic sequence. Bitumen filled inclusions within these cements indicate oil emplacement and carbonate cementation occurred simultaneously. Calcite oxygen isotope results suggest East Shetland Platform meteoric water, flushed the reservoir, biodegrading the migrated oil and displacing the original seawater. Biodegradation of oil took place at the palaeo-oil water contact, producing a laterally extensive cementation zone. Frequent oil leakage may have produced a series of different palaeo-oil water contacts which became preferential cementation sites. The Palaeocene Balmoral Field is located approximately 100kms to the south of Forth in Quad. 16, Block 21. To a large extent, the distribution of non-carbonate diagenetic phases in the Balmoral Field is controlled by lithoclast composition and the relative abundance of interbedded shales. Non ferroan and ferroan calcite concretions preferentially precipitated where there were localised accumulations of organic matter. The concretions precipitated at < 500m burial depth, sourced by bacterial oxidation and sulphate reduction of organic matter in meteoric pore fluids. Meteoric water is thought to have been derived from the East Shetland Platform to the north of Balmoral. Oil migrated into Balmoral during the Oligocene, post-dating meteoric flushing. Laterally extensive carbonate cements, formed in association with oil biodegradation, have the potential to compartmentalise a reservoir. The distribution of these cements within Tertiary reservoirs adjacent to the East Shetland Platform is likely to be controlled by the relative timing of meteoric flushing and oil migration.
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Almohsen, Fatma Khaled. "The compatibility of the Kuwait Project with the constitutional oil ownership concepts in the state of Kuwait : a critical and comparative legal analysis of the oil ownershp concepts of the United Kingdom and the state of Kuwait, with an analytical assessment of their application to the "Kuwait Project"." Thesis, University of Aberdeen, 2013. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=196003.
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Hindering important petroleum projects in Kuwait by the parliament under the pretext of preventing the violation of the oil ownership concepts included in the constitution is almost turning into a phenomenon. According to the Kuwaiti constitution, the natural resources are owned by the state, and consequently foreign oil ownership of national reserves is prohibited (Article 21 of the constitution). In addition, exploiting the national natural resources by other party than the state, though it is legally possibly, is restricted by several conditions (Article 152 of the constitution). The national petroleum project concerns the re-involvement of the international oil companies (IOCs) to develop production capacity from Kuwait’s northern oil fields, which is commonly known as the ‘Kuwait Project’, has met a considerable opposition by the parliament, and consequently has not been yet signed, in spite of the completion of its technical, financial and legal framework. The reason for opposing this project is that it, arguably, may include provisions contradicting with the constitutional framework for the exploitation of petroleum in Kuwait. Whether or not Kuwait’s oil ownership concepts stand as an obstacle to developing Kuwait’s oil production capacity requires examining the application of these concepts to the ‘Kuwait Project’. Such analysis will lead to accurately determine the effectiveness of these concepts when applied in practice and to identify aspects of possible incapability in addressing related issues.
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Matthews, Anna Louise. "Depositional and diagenetic controls on reservoir heterogeneity in the Valhall and Hod chalk fields, Norwegian North Sea." Thesis, University of Reading, 1998. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.270263.
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Aljuhani, Salem Gulaiyel. "Data integration for reservoir characterization : a central Arabian oil field /." Digital version accessible at:, 1999. http://wwwlib.umi.com/cr/utexas/main.
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Chavez, Ballesteros Luis Eladio. "Rapid assessment of redevelopment potential in marginal oil fields, application to the cut bank field." Texas A&M University, 2004. http://hdl.handle.net/1969.1/1389.
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Quantifying infill potential in marginal oil fields often involves several challenges. These include highly heterogeneous reservoir quality both horizontally and vertically, incomplete reservoir databases, considerably large amounts of data involving numerous wells, and different production and completion practices. The most accurate way to estimate infill potential is to conduct a detailed integrated reservoir study, which is often time-consuming and expensive for operators of marginal oil fields. Hence, there is a need for less-demanding methods that characterize and predict heterogeneity and production variability. As an alternative approach, various authors have used empirical or statistical analyses to model variable well performance. Many of the methods are based solely on the analysis of well location, production and time data.
My objective is to develop an enhanced method for rapid assessment of infill-drilling potential that would combine increased accuracy of simulation-based methods with times and costs associated with statistical methods. My proposed solution is to use reservoir simulation combined with automatic history matching to regress production data to determine the permeability distribution. Instead of matching on individual cell values of reservoir properties, I match on constant values of permeability within regions around each well. I then use the permeability distribution and an array of automated simulation predictions to determine infill drilling potential throughout the reservoir.
Infill predictions on a single-phase synthetic case showed greater accuracy than results from statistical techniques. The methodology successfully identified infill well locations on a synthetic case derived from Cut Bank field, a water-flooded oil reservoir. Analysis of the actual production and injection data from Cut Bank field was unsuccessful, mainly because of an incomplete production database and limitations in the commercial regression software I used.
In addition to providing more accurate results than previous empirical and statistical methods, the proposed method can also incorporate other types of data, such as geological data and fluid properties. The method can be applied in multiphase fluid situations and, since it is simulation based, it provides a platform for easy transition to more detailed analysis. Thus, the method can serve as a valuable reservoir management tool for operators of stripper oil fields.
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Acar, Cagdas. "Enhancing Petroleum Recovery From Heavy Oil Fields By Microwave Heating." Master's thesis, METU, 2007. http://etd.lib.metu.edu.tr/upload/12608403/index.pdf.
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There are many heavy oil reservoirs with thin pay zones (less than 10 m) in the world and in Turkey. Conventional steam injection techniques are not costeffective for such reservoirs, due to excessive heat loss through the overburden. Heat losses can be minimized through controlled heating of the pay zone. One such way is to introduce heat to the reservoir in a controlled manner is microwave heating. Laboratory studies on microwave heating of a scaled model of a heavy oil reservoir with a thin pay zone are presented with an economical feasibility of the method. In this thesis, three different conceptual oil reservoirs from south east Turkey are evaluated: Bati Raman (9.5 API) and Çamurlu (12 API) heavy crude oils and paraffinic Garzan (26 API)crude oil. Using a graphite core holder packed with crushed limestone with crude oil and water microwave effects of operational parameters like heating time and waiting period as well as rock and fluid properties like permeability, porosity, wettability, salinity, and initial water saturation are studied. The main recovery mechanisms for the experiments are viscosity reduction and gravity drainage. An analytical model is developed by coupling heat equation with the electromagnetic dissipated power per unit of volume based in Maxwell'
s equation successfully models the experiments for temperatures less than the pyrolysis temperature is presented. Also the experiments are scaled to the model by geometric similarity concept. In economic evaluation, the cost of oil is calculated based on domestic electricity prices.
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Al-Naumani, Yahya. "MPC for upstream oil & gas fields : a practical view." Thesis, University of Sheffield, 2017. http://etheses.whiterose.ac.uk/17979/.
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This work aims to improve corporate functional departments' confidence in adopting modern control approaches in new scenarios and thus presents control structure solutions based on model predictive control (MPC) for two control problems facing existing upstream oil and gas production plants. These are the disturbance growth in the series connected process and the control system dependency on operators. The suggested control solution integrates MPC as a master controller for the existing classical control of each subsystem, with a focus on those with high interaction phenomena. The proposed approach simply and inexpensively encompass MPC features such as predictions, optimizations, coordination and constraint handling as well as PID features like simplicity and ease of troubleshoot. In addition, the proposed control concept utilises the process safeguarding information and enhances the plant-wide optimal performance. The suggested control solution supports the role of control room operators, which is shown to reduce the growth in the impact of process disturbances. Compared with some alternative control structures (centralised MPC, decentralised MPC, distributed MPC (DMPC), and hierarchical DMPC) this proposal is simple, inexpensive to implement, and critically, builds on the local team operational experience and maintenance skills. Three process models were developed that representing the common gas treatment processes in upstream oil and gas plants, gas sweetening, gas dehydration and hydrocarbon dewopointing. The models were utilised to examine different control structures and proposals. These models are not only of benefit to studies on upstream oil and gas processes, but also to Large Scale Systems (LSS) in general. The models were used to analyse the disturbance impacts on a series connected processes, therefore to provide answers about how process malfunctions and different disturbances affect the processing operations. The proposed control system is designed on a cascade strategy and thus provides a flexible system control almost like a decentralised structure in dealing with disturbances and unit failures, and at the same time improves the closed loop performance and the plant-wide optimal operation. The control system contain MPC's that are designed to regulate the critical loops only while the rest of the uncritical loops will continue to function in a decentralised fashion under PID control algorithm. This minimises any design and set up costs, reduces demand on the communication network and simplifies any associated real time optimisations. The improved local control reduced the need for control room operator interactions with their associated weaknesses. The proposed control structure communicate with the process safeguarding system to enable prompt response to disturbances caused by unit failures, and shares critical information with adjacent MPC's, which indeed works as a feed-forward, to reduce the impact of process disturbances and enhance optimality. The control system design is simple, inexpensive to implement and significantly reduces the frequency of plant shut downs and saves on operating costs by properly controlling the disturbance growth in the process.
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Rabiei, Minou. "Excess water production diagnosis in oil fields using ensemble classifiers." Thesis, Curtin University, 2011. http://hdl.handle.net/20.500.11937/801.
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In hydrocarbon production, more often than not, oil is produced commingled with water. As long as the water production rate is below the economic level of water/oil ratio (WOR), no water shutoff treatment is needed. Problems arise when water production rate exceeds the WOR economic level, producing no or little oil with it. Oil and gas companies set aside a lot of resources for implementing strategies to effectively manage the production of the excessive water to minimize the environmental and economic impact of the produced water.However, due to lack of proper diagnostic techniques, the water shutoff technologies are not always proficiently applied. Most of the conventional techniques used for water diagnosis are only capable of identifying the existence of excess water and cannot pinpoint the exact type and cause of the water production. A common industrial practice is to monitor the trend of changes in WOR against time to identify two types of WPMs, namely coning and channelling. Although, in specific scenarios this approach may give reasonable results, it has been demonstrated that the WOR plots are not general and there are deficiencies in the current usage of these plots.Stepping away from traditional approach, we extracted predictive data points from plots of WOR against the oil recovery factor. We considered three different scenarios of pre-water production, post-water production with static reservoir characteristics and postwater without static reservoir characteristics for investigation. Next, we used tree-based ensemble classifiers to integrate the extracted data points with a range of basic reservoir characteristics and to unleash the predictive information hidden in the integrated data. Interpretability of the generated ensemble classifiers were improved by constructing a new dataset smeared from the original dataset, and generating a depictive tree for each ensemble using a combination of the new and original datasets. To generate the depictive tree we used a new class of tree classifiers called logistic model tree (LMT). LMT combines the linear logistic regression with the classification algorithm to overcome the disadvantages associated with either method.Our results show high prediction accuracy rates of at least 90%, 93% and 82% for the three considered scenarios and easy to implement workflow. Adoption of this methodology would lead to accurate and timely management of water production saving oil and gas companies considerable time and money.
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Ozkan, Erdal. "Performance of horizontal wells /." Access abstract and link to full text, 1988. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/8825498.
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Kaparthi, Prashanth. "Kinematic synthesis of a well service machine." Morgantown, W. Va. : [West Virginia University Libraries], 2001. http://etd.wvu.edu/templates/showETD.cfm?recnum=2244.
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Thesis (M.S.)--West Virginia University, 2001.Title from document title page. Document formatted into pages; contains viii, 64 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 63-64).
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Kristamsetty, Venkata. "Application of a statistical zonation technique to Granny Creek field in West Virginia." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4903.
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Thesis (M.S.)--West Virginia University, 2006.Title from document title page. Document formatted into pages; contains xx, 159 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 64-65).
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Hindle, Andrew D. "Modelling and evaluating petroleum migration pathways in the Paris, Williston and West of Shetlands and Wessex Basins." Thesis, Open University, 1998. http://oro.open.ac.uk/57868/.
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Petroleum migration pathways through a basin are determined by the three-dimensional distribution of discontinuous sealing surfaces, which are usually parallel to bedding. The petroleum migrates below the sealing surface taking the structurally most advantageous route. The three-dimensional distribution of migration pathways within the petroleum system can be modelled on a personal computer using a program based on the parameters developed during the research summarised in this thesis. Application of the model to the Paris, Williston, West of Shetlands and Wessex Basins demonstrates that a good correlation can be made between predicted pathways and discovered accumulations using simple models. Migration pathways form a dense network overlying hydrocarbon generating areas in the central parts of basins. Towards the basin margins they commonly become increasingly focused into discrete pathways by the sealing-surface morphologies. The Paris and Williston Basin research showed how relatively minor structuring of geological strata can result in a significant focusing of pathways. Eventually these pathways may reach the surface as shown by seepages. Research in the Wessex Basin revealed that reverse modelling of pathways from seeps assists in the prediction of the location of leaking accumulations. Deflection of the pathways from the structurally most advantageous route below the sealing surface may be caused by lateral sealing barriers due to facies variation in the carrier rock below the seal, fault juxtaposition, or cross-formational seals such as salt intrusions. Deflection of pathways also occurs where there are hydrodynamic conditions in response to topography-driven groundwater flow.
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Pyakurel, Sandeep. "3D P- and converted shear wave characteristics of the Morrow production trend in the Buffalo Valley field, Chaves-Eddy County, New Mexico." Morgantown, W. Va. : [West Virginia University Libraries], 2005. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4256.
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Thesis (M.S.)--West Virginia University, 2005.Title from document title page. Document formatted into pages; contains xi, 145 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 141-145).
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Josson, Erika M. Atchley Stacy C. "Controls on reservoir continuity and distribution within the Mississippian Pekisko Formation at Twining field, south-central Alberta, Canada." Waco, Tex. : Baylor University, 2006. http://hdl.handle.net/2104/4876.
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Ogutcu, Gokcen. "Risk Assessement Of Petroleum Transportation Pipeline In Some Turkish Oil Fields." Master's thesis, METU, 2004. http://etd.lib.metu.edu.tr/upload/12605151/index.pdf.
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In this thesis, quantitative risk assessment study of several oil field
transportation lines that belong to a private oil production company located in S.
East Turkey has been conducted. In order to achieve this goal, first primary risk
drivers were identified. Then relative ranking of all pipeline segments were
conducted. Quantitative risk assessment was based on Monte Carlo simulations
and a relative scoring index approach. In these simulations frequency of
occurrence of pipeline failures for different oil field pipeline systems was used.
Consequences of failures were also based on historical data gathered from the
same oil fields. Results of corrosion rate calculations in oil and water pipeline
systems were also reported.
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Most significant failures are identified as corrosion, third party damage,
mechanical failure, operational failure, weather effect and sabotage. It was
suggested that in order to reduce corrosion rate, thin metal sheets must be inserted
in pipelines. Aluminum sheets (anodes) must be used to reduce corrosion rate in
water pipeline system. The required number of anodes was calculated as 266 for
BE field water pipeline (the life of anode is 1.28 years), 959 for KA water
pipelines system (the life of anode is 3.2 years.) and 992 for KW water pipelines
(the life of anode is approximately 2 years). Furthermore high risk pipeline
segments for further assessment were identified. As a result of Monte Carlo
simulations, the highest risk was observed in return lines followed by flow lines,
water lines and trunk lines. The most risky field was field BE for which the risk
value in trunk lines were the highest followed by flow lines. Field SA was the
second risky region for flow lines and it was followed by KU region. Field KA
was forth-risky. Prioritization of maintenance activities was suggested and areas
of missing or incomplete data were identified.
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Nordbø, Henrik. "Optimal configuration of supply logistics for remote oil and gas fields." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for marin teknikk, 2013. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-22333.
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The objective of this thesis has been to compare alternatives to improve the supply service for remote locations offshore. First the alternative of running a conventional supply service has been assessed, where the platform supply vessels (PSVs) sailed directly from a land depot to supply the installations with commodities. The alternative to the conventional supply service was to have two converted cargo ships in use as storage units located at the oil and gas field which deliver cargo to the PSVs. For the alternative with the storage units the ships switch position, when one is in operation the other one goes to shore and stock up on supplies. PSVs are expensive and if one can reduce the number of ships in operation it will grant great savings for the operator of the oil and gas field. Having storage units located in the proximity of the installations offshore will reduce the sailing distance of the PSVs to a fraction of the original sailing distance from a land depot. While the cost of the PSVs will be reduced one has a cost increase due to the storage units. Finding the point at which the storage units can become profitable has been the essence of this thesis. A case study has been made to compare the two different setups for oil and gas activities outside Jan Mayen. It was expected a maximum activity level with three installations in operation. The case study has been made more general by adding up to five additional installations to get a better look at the savings of having the storage units with more installations to service. To minimize the costs of each setup it was made a mathematical formulation for each of them. For the regular setup the minimum cost of routing the supply vessels was found from a land depot, given a required supply frequency of the installations. The port in Kristiansund has been chosen as a suitable land depot for this case study. In the setup with storage units the routing from the storage units with PSVs are considered in addition to the cost of the storage units. To minimize the routing cost from the storage units the mathematical model had to consider different locations of the units. Both of the setups have the same input data as a basis to get a good comparison. The models are solved for a weekly planning period. Some basic design characteristics of the storage units have been made. It was concluded that open hatch bulk carriers would be most suited for the operation. The vessels to be converted should have a deadweight capacity of around 57 300 tons. It is estimated here that the cost of one storage unit will be 53 000 USD per day. This price may not be very accurate and is based on many assumptions due to lack of assessable cost information, but it has been tried to make a conservative estimate. The mathematical formulations of the models have been solved with the optimization software Xpress. For the regular supply service from land the total cost of the supply service ranged from 590 000 USD per week for three installations and up to 1 550 000 USD for eight installations. The results showed that there was a linear increase in cost when increasing the number of installations to supply. Compared to the setup with the converted cargo ships the total costs ranged from 916 000 USD per week for three installations to 1 137 000 USD per week for eight installations. In this case the cost per installation gets lower with the number of installations to supply. When solving the model for the supply service from land one gets larger ships in operation which can visit as many installations as possible on a route as they can only make one trip per week. Compared to the case with the storage units one gets a few smaller PSVs in operation which can sail many routes per week. It has been found that the concept with the storage units would be profitable with 6 installations or more to service in this case. With less than 6 installations to service it would be more expensive to have storage units than running a regular supply service from land. Generally it can be concluded that having the storage units could be profitable if there is enough installations to service. The other factor with the biggest effect on the problem is the distance to shore, however, finding at what distance from shore the storage unit becomes profitable was not included in this study. The final conclusion of the work here is that the use of storage units could reduce the cost of the supply service, and is an interesting concept that should be studied further.
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Gonzalez, Daniel G. "Basic building blocks of real-time data analysis as applied to smart oil fields." Morgantown, W. Va. : [West Virginia University Libraries], 2007. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=5370.
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Thesis (M.S.)--West Virginia University, 2007.Title from document title page. Document formatted into pages; contains xii, 136 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 75-76).
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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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Wolpert, Jeremy M. "Stratigraphic and structural analysis of the J1 Sandstone, Scotts Bluff Trend, Scotts Bluff and Morrill counties, Nebraska." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4925.
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Thesis (M.S.)--West Virginia University, 2006.Title from document title page. Document formatted into pages; contains xi, 103 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 90).
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Pay, Mark D. "Diagenesis and reservoir quality of the Devonian-carboniferous sandstones of the Clair Field, west of Scotland, UK." Thesis, University of Reading, 1998. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.267427.
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Taylor, Katherine Sarah. "Ephemeral-fluvial sediments as potential hydrocarbon reservoirs." Thesis, University of Aberdeen, 1994. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=123206.
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Although reservoirs formed from ephemeral-fluvial sandstones have previously been considered relatively simple, unresolved problems of sandbody correlation and production anomalies demonstrate the need for improved understanding of their internal complexity. Ephemeral flows occur in direct response to precipitation, receiving little or no water from springs or other long-continued sources. They consequently predominate in dryland regions where precipitation is high in intensity, short lived and of limited areal extent. Resulting flow is high energy, relatively shallow and also restricted in duration and areal coverage. High transmission losses, abundant loose material and sparse vegetation result in highly concentrated flows which dissipate rapidly, causing a downstream decrease in flow discharge. Sediments deposited from these flows include parallel laminated sands, massive sands, scour-fill sands, transitional lower to upper flow regime dunes, and commonly contain numerous erosional discontinuities, scattered mudclasts, rapid grain size changes and deformational features. Large quantities of rainfall falling over longer periods produces steady flows dominated by well sorted, lower flow regime bedforms which have moderately well developed fining-up sequences. High intensity rainfall falling for shorter periods produces unsteady flows which are characterised by more poorly sorted, upper flow regime bedforms and an absence of fining-up sequences. Outcropping ephemeral-fluvial systems have been studied in order to determine the main features and processes occurring in sand-rich ephemeral systems and to identify which features will be of importance in a hydrocarbon reservoir. The Lower Jurassic Upper Moenave and Kayenta Formations of south-eastern Utah and northern Arizona comprise complex series of stacked, sand-dominated sheet-like palaeochannels suggestive of low sinuosity, braided systems.
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Wan, Zahari Wan Mohd Zulhafiz Bin. "Unbalanced indemnities : a comparative analysis of risk allocation in oilfield service contracts in Malaysia, the UK and USA." Thesis, University of Aberdeen, 2016. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=230170.
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Nasakul, Siree. "Thermoreversible gels and temperature triggered kinetically controlled gels for oilfield applications /." Digital version accessible at:, 2000. http://wwwlib.umi.com/cr/utexas/main.
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Cook, Joshua R. "Development of a program to gather and process data from oil and gas fields." Morgantown, W. Va. : [West Virginia University Libraries], 2004. https://etd.wvu.edu/etd/controller.jsp?moduleName=documentdata&jsp%5FetdId=3727.
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Thesis (M.S.)--West Virginia University, 2004.Title from document title page. Document formatted into pages; contains ix, 80 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 33-34).
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Udoh, Tinuola H. "Productivity enhancement in a combined controlled salinity water and bio-surfactant injection projects." Thesis, University of Aberdeen, 2018. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=238375.
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NAVEIRO, JAIME TURAZZI. "DEVELOPMENT OF OIL FIELDS CONSIDERING THE PRESENCE OF CO2: THEORETICAL FRAMEWORK AND CASE STUDY." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2012. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=21095@1.
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A degradação do meio ambiente está no topo da agenda de países e empresas. O foco principal é a redução das emissões de gases causadores do efeito estufa, sendo CO2 o maior contribuinte. O consumo elevado de combustíveis fósseis está criando um efeito irreversível no planeta. De forma a contrabalancear seus impactos ambientais, surge o segmento de projetos de captura e sequestro de carbono. O maior entrave seu para crescimento é econômico, daí o uso de CO2 para recuperação avançada de óleo, alavancando sua implementação. Esta dissertação avalia duas estratégias distintas de desenvolvimento de um campo de petróleo offshore, uma através da injeção de água e outra por recuperação avançada com injeção de CO2 (EOR CO2 – enhanced oil recovery) a partir de fonte antropogência. Os maiores desafios técnicos para aplicação de EOR CO2 em ambiente offshore são examinados, mostrando o arcabouço teórico, melhores práticas e soluções ainda não desenvolvidas, em áreas como: gerenciamento de reservatórios, engenharia de poços e plantas de processo, além de captura e transporte de CO2. Em seguida, a viabilidade econômica de ambos os métodos de recuperação são comparados, com pequena vantagem o caso EOR. Entretanto, devido às incertezas de sucesso do método e sua sensibilidade ao preço de importação de CO2, a gama de resultados pode alterar o processo decisório. Um balanço de carbono também é realizado, mostrando a redução esperada de sua concentração na atmosfera ao se selecionar o método de EOR CO2. Ainda, a aplicabilidade de créditos de carbono é discutida, e seu impacto econômico quantificado. Finalmente, há um longo caminho a se percorrer para ampla utilização de projetos EOR com CO2 antropogênico em ambiente offshore. Ao apontar os maiores desafios e entraves a serem superados, incluindo técnicos, comerciais e regulatórios, ao apresentar modelo econômico, e acima de tudo, ao mostrar sua atratividade, esta dissertação tem por objetivo reduzir esta distância.Environmental issues are on top of governments and companies’ agendas. The main focus is on global warming and means to reduce greenhouse gases, being carbon dioxide the main contributor. The consumption of fossil fuels is creating an irreversible effect on the planet, and it is expected to continue for years to come. In order to offset its usage are the emerging carbon capture and storage (CCS) projects. Their main obstacle is economical, and that’s where enhanced oil recovery through CO2 can help. This dissertation assesses the development options of an offshore Brazilian discovery, by comparing water injection method with carbon dioxide enhanced oil recovery (EOR CO2) imported from an anthropogenic onshore source. The main EOR CO2 technical challenges for offshore application are examined, detailing field proven and yet to be developed solutions, from reservoir management, wells engineering to the production unit, passing through CO2 acquisition and transportation. Next, economical feasibility of both methods are compared, with a slight advantage for EOR on the base case. Nevertheless, due to high uncertainties in method success prior to development and commitment, and also to carbon dioxide import prices, the range of results can shift the decision making, and such sensitivity analysis is also presented. A carbon inventory is also made, showing the net positive balance of selecting EOR CO2, which reduces the component’s concentration in the atmosphere. Finally, the applicability of carbon credits is discussed and its economical impact quantified. There is still a long way to go for the widespread utilization of anthropogenic EOR CO2 in offshore projects. By pointing out the main challenges to be addressed, including technical, commercial and regulatory, by presenting an economical model comprising environmental aspects, and most of all, showing its attractiveness, this dissertation aims to reduce this gap.
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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.
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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
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Devine, Carol A. "16S ribosomal DNA analysis of microbial populations associated with hydrocarbon reservoirs." Thesis, University of Aberdeen, 2000. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.312360.
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The sulphate-reducing bacteria (SRB) are a diverse group of organisms which use sulphate as a terminal electron acceptor and produce the highly toxic gas, hydrogen sulphide. The deleterious effects of this include hydrocarbon reservoir souring, formation damage and microbial corrosion. The SRB are of major economic importance to the oil industry. However, knowledge of the microbial ecology of the deep subsurface remains limited. The aim of this project was to investigate whether organisms are indigenous to the hydrocarbon formation and/or are introduced during drilling operations. A range of molecular techniques such as 16S rDNA sequence analysis, probing with labelled oligonucleotides, and denaturing gradient gel electrophoresis (DGGE) were employed to investigate the microbial diversity in oil field samples. A wide range of bacterial 16S rDNA sequences were identified using these molecular methods. An analysis of drilling mud samples revealed a diverse range of bacterial 16S rDNA sequences confirming that bacteria, including SRB, can be introduced to the reservoir during drilling operations. A number of bacterial 16S rDNA sequences were recovered from a geological core sample taken from a depth of 9,770 feet. The microbial diversity was remarkable in such a high temperature, high pressure environment. This lends credence to the theory that certain bacteria may be indigenous to the subsurface environment. Scanning electron micrographs of core which had been incubated in growth medium indicated the presence of 'nannobacteria'. These tiny coccoids, with a diameter of only 0.1 μm are far smaller than the generally accepted minimum size for cellular life forms. The nannobacteria grew in regular colony shaped structures and were seen only in sections taken from inside the rock. This study indicates that hydrocarbon reservoirs provide an environment in which bacteria, if introduced during drill operations, may become established. However, the subsurface also contains complex indigenous microbial populations that demonstrate considerable species diversity and may include unrecognised life forms.
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Thorpe, Dean Timothy. "Controls on reservoir quality in Early Cretaceous carbonate oil fields and implications for basin modelling." Thesis, University of Edinburgh, 2014. http://hdl.handle.net/1842/18014.
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Carbonate reservoirs hold more than 50 % of Earth’s remaining conventional hydrocarbon. However, recovery from these reservoirs is notoriously difficult due to the complex and multiple scales of porosity. This heterogeneity is a function of both the depositional environment and of subsequent diagenetic processes. This thesis examines the processes that have controlled the reservoir quality of three Early Cretaceous carbonate oil fields (A, B, and C), in particular the role of deposition, diagenesis and the timing of oil charge in controlling final properties. Results are then used to help provide a theoretical basis for the modelling and prediction of reservoir quality and to improve the calibration of basin models. Field A and B are stacked and highly compartmentalised giant oil fields in the U.A.E. that are dominated by muddy fabrics and have a highly variable porosity (0- 35 %) and permeability (0.01-830 mD). Although the depositional environment strongly determines the location of reservoirs extensive diagenesis, through cementation and dissolution, has greatly modified the porosity and permeability of the reservoirs. Bulk δ13C values obtained from the main pore occluding calcite and dolomite cements are similar to the δ13C values of bulk micrite for the reservoir interval in which they are now present. This suggests that the cements that are occluding the pore space in each stacked reservoir are locally sourced and implies that each reservoir behaves as a relatively closed system during cement precipitation. In-situ (SIMS) δ18OVPDB values were obtained for the complete calcite cementation history of multiple reservoirs in Field A and B. The δ18OVPDB values for the first (oldest) calcite cement zone in each reservoir can be related to the global δ18OVPDB marine curve during the Hauterivian-Aptian and to million-year scale major climatic cooling events. The δ18OVPDB values for successive cement zones then progressively decrease, which is related to successive precipitation as a result of increasing temperature during burial in a relatively closed system. In-situ (SIMS) δ18OVPDB data together with oil inclusion occurrence suggest that initial oil charge (from the Dukhan Formation), at ~ 55-45 Million years ago (Mya) in Field A, reduced the cementation rate in the oil reservoir and preserved porosity. Whereas in the coeval aquifer a large volume of cement precipitated, after oil entered the oil reservoir, that greatly reduced porosity. Furthermore, the most reduced δ18OVPDB and mMg/mCa values are obtained from the cements in the shallowest (youngest) reservoirs, suggesting that cementation ceased in the deepest reservoirs first. This can be related to hydrocarbon stopping cementation or to the complete occlusion of effective porosity in the older reservoirs prior to the younger. After calcite and dolomite cementation ceased in the reservoirs of Field A and B a large scale dissolution event has been identified which significantly enhanced porosity. This dissolution event is then followed by the precipitation of authigenic kaolinite. Basin modelling reveals that this dissolution event is likely to be related to the thermal maturation of sedimentary organic matter that is present within local intraformational seals and to the migration of organic acids prior to a second hydrocarbon charging event (at ~ 45 Mya). The aluminium, that is required for the formation of kaolinite, would then have been brought into the system by complexing with the organic compounds derived from this maturation event. Field C is an oil field located in offshore Brazil. The field is dominated by high energy facies that have porosities which range from 5 % to 39 %, and permeabilities from 0.1 mD to 8.1 D. The depositional poro-perm properties of the oil reservoir have undergone little diagenetic alteration; however, the aquifer is extensively cemented and the porosity is much reduced. All the cements identified, by both petrography and stable isotopic analyses, in the oil reservoir are early and are thought to have formed from a pore fluid similar to, or slightly evolved from, Early Cretaceous seawater. Basin modelling suggests that oil may have entered the field slightly after deposition (at ~105 Mya) and led to the preservation of high porosities and permeabilities in the oil reservoir by stopping cementation.
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Aggrey, George Hayford. "A study of intelligent oil and gas fields' real time optimisation and its value quantification." Thesis, Heriot-Watt University, 2007. http://hdl.handle.net/10399/60.
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The thesis, "Intelligent Fields Added Value Quantification and Real Time Value Creation", covers the "added value" evaluation process and a novel extension of the use of real time pressure data of Intelligent Fields. Intelligent well completion technologies add value via real time optimisation and provide flexibility for future well control. The correct "value adding" evaluation must be developed to become part of the general optimisation process. Hence understanding the value added, which is dependent on the three main factors of additional cost, reliability and equipment functionality. is key to the success of Intelligent Well Technology (I WT). This thesis explores the added value quantification criteria and develops a widely applicable software for quantifying the value added by Intelligent Well Technology and Sensor applications. The work explores and compares the various valuation criteria and their applicability to "Added Value from IWT" whilst modelling the application in various reservoir environments. The importance of the future equipment functionality in the value creation definition is investigated and rigorously factored into the value assessment. Current modelling and optimisation techniques were employed to show the values associated with intelligent completions and with various permanent downhole sensors. Appropriate use of intelligent production information is necessary to effectively contribute to improve operational performance. To achieve this, data driven management techniques such as Artificial Neural Network (ANN) with Wavelets and Time Series were used for the analysis of real time data to create the necessary information. Alternatively, a model driven approach (unlike NN "black" box) which considers the underlying physics of fluid flow in the reservoir and realistically captures the wellborereservoir flow processes is used to show that real time downhole pressure can detect the time and source of water influx into a multi-zone horizontal or near horizontal completion thus permitting a more rapid response to water breakthrough.
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TOZZO, Everton. "A hybrid multi-objective genetic algorithm for scheduling heterogeneous workover rigs on onshore oil fields." Universidade Federal de Pernambuco, 2017. https://repositorio.ufpe.br/handle/123456789/23757.
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CNPQ
Campos de produção de petróleo terrestres são compostos por um conjunto de poços de petróleo que, depois de certo tempo em operação, podem apresentar algum tipo de mau funcionamento e ter a produção interrompida. Quando isso ocorre, veículos especialmente equipados, também chamados sondas de manutenção, são utilizados para prestação de serviço nos poços e garantir que suas atividades sejam reestabelecidas. Dado um número limitado de sondas de manutenção e a grande quantidade de poços existentes no campo de petróleo, o problema das sondas de manutenção consiste em encontrar o melhor escalonamento para as mesmas de modo que a perda de produção total dos poços seja minimizada. O escalonamento dos poços considera alguns fatores como a taxa de perda de produção por poço, o nível de atendimento requerido e o horizonte de planejamento para o qual o escalonamento será executado. Este trabalho apresenta um algoritmo genético híbrido para a resolução do problema de sondas de manutenção com múltiplos objetivos, frota heterogênea e horizonte de planejamento finito. O algoritmo genético híbrido incorpora uma heurística de descida em vizinhança variável como método de busca local para aumentar a velocidade de convergência do conjunto de soluções. São considerados os objetivos de minimização da perda de produção e custo com frota associado ao aluguel das sondas de manutenção. A frota é mantida variável, portanto um depósito de sondas é incluído em uma posição estratégica no campo de produção de petróleo para garantir que as novas sondas de manutenção, além das já espalhadas no campo, possam ser incluídas no escalonamento quando requeridas. O algoritmo genético foi testado em um conjunto de instâncias com até 200 poços, 10 sondas de manutenção e horizonte de planejamento igual a 300. Os resultados demonstram um alto conflito entre os objetivos de minimização da perda de produção e o custo da frota para o problema das sondas de manutenção, além de importantes aspectos relacionados às soluções obtidas pelo algoritmo proposto aplicado ao problema.
Onshore oil fields are composed by a set of geographically distributed wells that, after some time of operation, might present some malfunction and have their production interrupted. When the oil production of some wells is interrupted, specially-equipped vehicles, also called workover rigs, are deployed to service the wells and guarantee that their activity is restored. Given the limited number of workover rigs and the large number of wells around the oil field, the workover rig problem consists in finding the best scheduling for the workover rigs so the total production loss of wells is minimized. The scheduling considers some factors such as the production loss rate of each well, the service level required and the planning time horizon in which the scheduling must be executed. This research presents a hybrid genetic algorithm to solve the multi-objective workover rig problem with a heterogeneous fleet and a finite time horizon. The hybrid genetic algorithm incorporates a variable neighborhood descent heuristic as a local search procedure to increase the convergence speed of the set of solutions. Both objectives of minimization of the production loss and fleet cost associated to the rent of workover rigs are taken in consideration. The fleet is held variable, so a workover rig depot is included at a strategic position on the oil field in order to guarantee that new workover rigs, besides the already existent ones on the oil field, might be included in the scheduling when required. The genetic algorithm was tested on a set of practical-sized instances up to 200 wells, 10 workover rigs and 300 period horizon. Results show a high conflict between the objectives of minimizing the production loss and fleet cost for the workover rig problem, besides important aspects of the solutions obtained by the proposed algorithm to solve the problem.
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Badescu, Adrian Constantin. "Reservoir characterization of the Miocene Starfak and Tiger Shoal fields, offshore Louisiana through integration of sequence stratigraphy, 3-D seismic, and well-log data." Access restricted to users with UT Austin EID, 2002. http://wwwlib.umi.com/cr/utexas/fullcit?p3108452.
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Metz, William M. "The historical archaeology of the oil and gas industry in Wyoming." Virtual Press, 1986. http://liblink.bsu.edu/uhtbin/catkey/458522.
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The history and archaeology of the oil and gas industry has received little attention in cultural resource management. The sites of early exploration activity are being destroyed rapidly due, in part, to the fact that field archaeologists and historians have not been educated on the scientific and historical importance of this industry to the American culture. This thesis is an attempt to begin the education process. The document begins with an overview of the historical developments on a national level and in the State of Wyoming. Attention is then focused on the physical remains that can be found in the field with guidance on the identification, interpretation, and evaluation of the remains. The thesis concludes with the development of research, designs and avenues of future inquiry.
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Kaya, Egemen Tangut. "Estimation Of Expected Monetary Values Of Selected Turkish Oil Fields Using Two Different Risk Assessment Methods." Master's thesis, METU, 2004. http://etd.lib.metu.edu.tr/upload/1091495/index.pdf.
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Most investments in the oil and gas industry involve considerable risk with a wide range of potential outcomes for a particular project. However, many economic evaluations are based on the &ldquomost likely&rdquo
results of variables that could be expected without sufficient consideration given to other possible outcomes and it is well known that initial estimates of all these variables have uncertainty. The data is usually obtained during drilling of the initial oil well and the sources are geophysical (seismic surveys) for formation depths and areal extent of the reservoir trap, well logs for formation tops and bottoms, formation porosity, water saturation and possible permeable strata, core analysis for porosity and saturation data and DST (Drill-Stem Test) for possible oil production rates and samples for PVT (Pressure Volume Temperature) analysis to obtain FVF (Formation Volume Factor) and others. The question is how certain are the values of these variables and what is the probability of these values to occur in the reservoir to evaluate the possible risks. One of the most highly appreciable applications of the risk assessment is the estimation of volumetric reserves of hydrocarbon reservoirs. Monte Carlo and moment technique consider entire ranges of the variables of Original Oil in Place (OOIP) formula rather than deterministic figures. In the present work, predictions were made about how statistical distribution and descriptive statistics of porosity, thickness, area, water saturation, recovery factor, and oil formation volume factor affect the simulated OOIP values. The current work presents the case of two different oil fields in Turkey. It was found that both techniques produce similar results for 95%. The difference between estimated values increases as the percentages decrease from 50% and 5% probability.
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Kazemi, Kazem. "Seismic imaging of thrust fault structures in Zagros iranian oil fields, from surface and well data." Cergy-Pontoise, 2009. http://www.theses.fr/2009CERG0401.
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L’objectif de cette thèse est de mieux comprendre la structure de ce champ, connu principalement par les puits de production, grâce à la première sismique 3D récemment acquise et en intégrant les informations fournies par la sismique de puits. Étant donné l’importance des pendages, les réflexions en sismique de puits zéro offset sont attendues principalement sur les composantes horizontales. Une méthode originale d’orientation des 3 composantes est employée et les résultats confirment la présence de réflecteurs pentés. Les résultats migrés en profondeur sont plus précis dans le recouvrement mais la zone réservoir n’est pas améliorée, car les images temps ne permettent pas de mesurer les pendages et courbures résiduelles dans la zone d’intérêt en raison de forts multiples et d’un niveau de bruit important. Une nouvelle technique prototype de migration PSTM, permettant une sélection de l’azimut, du pendage géologique et la recherche automatique du meilleur pendage locale est présentéeThe objective of the present PhD thesis is to improve the structural understanding of the Aghajari field using 3D seismic imaging, and well seismic. The lack of seismic response of the dipping horizons in the reservoir oil zone constitutes a major identified difficulty. Given the dip values of the reflectors in the pay zone, the P-P reflections are expected to appear mainly on the horizontal components of the VSP data, justifying the processing of the 3 components. An innovative method of 3C VSP orientation was developed. Several new approaches of seismic imaging have been applied in order to investigate and improve the reservoir illumination. The depth migrated image is improved in the overburden, but not at reservoir level,due to low signal to noise, thus poor dip and velocity determination in the reservoir interval. A new Kirchhoff PSTM prototype technique, allowing selection of azimuth sector, offset range and geological dip,with automatic optimization of the local dip is presented
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AL-Rashidi, Abdulrahman F. "Designing neural networks for the prediction of the drilling parameters for Kuwait oil and gas fields." Morgantown, W. Va. : [West Virginia University Libraries], 1999. http://etd.wvu.edu/templates/showETD.cfm?recnum=1209.
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Thesis (M.S.)--West Virginia University, 1999.Title from document title page. Document formatted into pages; contains x, 76 p. : ill. (some col.), map (some col.). Includes abstract. Includes bibliographical references (p. 54-55).
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Nakanishi, Takeshi. "Practical application of sequence stratigraphy and risk analysis for stratigraphic trap exploration." Title page, contents and abstract only, 2002. http://web4.library.adelaide.edu.au/theses/09PH/09phn1635.pdf.
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"September 2002" Includes bibliographical references (leaves 200-209) Outlines an evaluation procedure for stratigraphic trap exploration by employing sequence stratigraphy, 3D seismic data visualisation and quantitative risk analysis with case studies in an actual exploration basin.
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Ishkov, Oleg Yuryevich. "Analysis and modelling of in situ geochemical reactions in oil fields based on produced Brine chemistry data." Thesis, Heriot-Watt University, 2010. http://hdl.handle.net/10399/2347.
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Management of mineral scale precipitation is one of the major challenges faced by the oil industry. Total costs of scale prevention can exceed £1 million for a field or even sometimes for a single well. Identification of the injection water fraction in the produced brine stream is of importance to production chemists involved in mineral scale prevention. This data is required to determine the onset and the severity of barium sulphate precipitation, one of the most challenging flow assurance issues in the oilfield due to the very low solubility of the mineral. This body of work develops a solution to the problem of how to determine the injection water (IW) fraction in the produced brine. A robust and accurate method for calculating IW fraction in produced water samples is presented. The method has been named the “Reacting Ions” method. The Reacting Ions method is based on interactions between ions during reactions, by correctly taking account of ion losses that will occur due to precipitation. The proposed new method allows injection water fraction to be calculated from concentrations of the ions involved in reactions, which has never been done before. In addition, the new method incorporates as a limiting case the Ion Track method - the most widespread method currently used in the industry. The Reacting Ions method removes the limitation that only conservative ions can be used to track injection brine in produced water. This Reacting Ions method is applied to a synthetic produced water case, generated using a reservoir simulator, where the “correct” IW fraction is known, and a very good match is achieved, even when significant noise is applied to the synthetic data. An additional outcome of the synthetic case tests is that conventional use of sulphate in the Ion Track method leads to a late detection of injection water breakthrough, while the Reacting Ions method based on barium and sulphate is significantly more accurate. Delayed detection of injection water breakthrough can lead to the onset of scaling before preventative measures have been taken. The Reacting Ions method was applied in the analysis of produced brines for more than 100 wells in several regions of the North Sea. Results of the study presented here show that the method is generally more effective in detecting IW fractions than conventional ion tracking techniques, especially at low IW fractions soon after breakthrough occurs. Using barium and sulphate, the new Reacting Ions method benefits from near zero end-point concentrations of iii these two ions that is typical for North Sea brines, and is consequence of the low solubility of barite. The more accurate identification of IW fraction has led to the development of three applications that use the Reacting Ions method. In the first, the relative ion deviations are used to identify whether an ion is conservative, precipitating or part of a dissolution reaction. This information can be applied by production chemists to predict possible types of mineral scale occurring. The second application assists in detecting which formation or formations the well is producing from, which gives incremental information about the reservoir itself. In the third, a method to analyse squeeze treatment response is proposed. The impact of scale inhibitor placement on the ion concentrations is evaluated, and thus a judgement can be made regarding the overall effect of the squeeze treatment in stopping the identified scale reactions from happening. All three new applications were successfully applied to field data.
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Slater, Colin P. "Estimation and modelling of anisotropy in vertical and walkaway seismic profiles at two North Caucasus oil fields." Thesis, University of Edinburgh, 1997. http://hdl.handle.net/1842/11395.
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This thesis considers anisotropy of seismic wave propagation at two oil fields in the North Caucasus region of Russia. In both oil fields, the reservoir zone displays a strong lateral variation in productivity which is thought to be caused by variations in fracture intensity. Such fractures may cause azimuthal anisotropy which can be detected in Vertical Seismic Profiles (VSPs) and Walkaway VSPs. The main aim of the thesis is to characterise this azimuthal anisotropy at three of the oil wells in these fields and to compare this anisotropy with productivity. At each of the three wells, I determine azimuthal anisotropy from VSPs by the application of techniques for estimating shear-wave splitting. I find that the polarisation direction of the fast shear-wave at all three wells is aligned approximately NNE-SSW. At two of the wells, forward modelling shows that the shear-wave splitting parameters in the top 1km can be closely matched by a model containing aligned, vertical fractures, striking NNE-SSW, in approximately the top 1 km. I am unable to resolve the anisotropy of the reservoir zone at these two wells. At the third well, strong azimuthal anisotropy of the reservoir zone is indicated by a large decrease of time delay between shear-waves propagating along vertical raypaths. This decrease is interpreted as an orthogonal rotation of the fast shear-wave polarisation direction at a depth just above the reservoir zone. Using forward modelling, I successfully match these observations with three different fractured reservoir models: the first model contains vertical fractures striking orthogonal to the presumed maximum horizontal stress direction; the second model has dipping fractures striking parallel to the maximum horizontal stress direction; and the third model has a distribution of fractures with a high internal pore-fluid pressure. Consideration of only vertical raypaths through the reservoir cannot discriminate between these models. However, modelling of non-vertical propagation from far-offset VSPs suggests that the dipping fracture model is the better model, although the lack of observations above the reservoir at this well means that other interpretations cannot be excluded.
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Chapman, James Lawson. "The modern great game in Central Asia oil, terrorism, and human rights /." CONNECT TO THIS TITLE ONLINE, 2006. http://etd.lib.umt.edu/theses/available/etd-12152006-214828/.
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Ghous, Abid Petroleum Engineering Faculty of Engineering UNSW. "Digital formation evaluation via x-ray micro-computed tomography." Awarded by:University of New South Wales. School of Petroleum Engineering, 2005. http://handle.unsw.edu.au/1959.4/20581.
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Machined fragments of 10 core plugs from oshore reservoirs have been analysed using a high resolution X-ray micro-computed tomography (micro-CT) facility. The facility includes a system capable of acquiring 3D images made up of 20003 voxels on core plugs up to 6 cm diameter with resolutions down to 2 um. The cores analysed include six cores from a gas reservoir and four cores from an oil reservoir. The cores exhibit a very broad range of pore and grain sizes, porosity, permeability and mineralogy. The petrological data, available only for gas reservoir cores, is compared with the data obtained from the tomographic images. Computational results made directly on the digitized tomographic images are presented for the permeability, formation factor, resistivity index and drainage capillary pressure across a range of . We show that data over a range of porosity can be computed from a single fragment. We compare the computations of petrophysical data on fragments to conventional laboratory measurements on the full plug. Permeability predictions from digital and conventional core analysis are consistent. It is shown that a characteristic length scale can be dened as a quality control parameter for the estimation of permeability. Results for formation factor, drainage capillary pressure and resistivity index are encouraging. The results demonstrate the potential to predict petrophysical properties from core material not suited for laboratory testing (e.g., sidewall or damaged core and drill cuttings) and the feasibility of combining digitized images with numerical calculations to predict properties and derive correlations for specic rock lithologies. The small sample size required for analysis makes it possible to produce multiple measurements on a single plug. This represents a potential multiplier on the quantity of core data allowing meaningful distributions or spreads in petrophysical properties to be estimated. We discuss the current limitations of the methodology and suggest improvements; in particular the need to calibrate the simulated data to parallel laboratory core measurements. We also describe the potential to extend the methodology to a wider range of petrophysical properties. This development could lead to a more systematic study of the assumptions, interpretations and analysis methods commonly applied within industry and lead to better correlations between petrophysical properties and log measurements.
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Torrente, Maria Laura. "Applications of Algebra in the Oil Industry." Doctoral thesis, Scuola Normale Superiore, 2009. http://hdl.handle.net/11384/85681.
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Al-Shamkhani, Maher T. Abdul-Zahra. "Managing, Controlling and Improving the Treatment of Produced Water Using the Six Sigma Methodology for the Iraqi Oil Fields." Master's thesis, University of Central Florida, 2013. http://digital.library.ucf.edu/cdm/ref/collection/ETD/id/5595.
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Produced Water (PW) is the largest volume of waste that is normally generated during oil and gas production. It has large amounts of contaminants that can cause negative environmental and economic impacts. The management method for PW relies highly on types and concentrations of these contaminants, which are field dependent and can vary from one oil field to another. Produced water can be converted to fresh water if these contaminants are removed or reduced to the acceptable drinking water quality level. In addition, increasing oil production rate and reducing amounts of discharged harmful contaminants can be achieved by removing dissolved hydrocarbons from PW. In order to identify the types of these contaminants, effective tools and methods should be used. Six Sigma, which uses the DMAIC (Define- Measure- Analyze- Improve- Control) problem-solving approach is one of the most effective tools to identify the root causes of having high percentages of contaminants in produced water. The methodology also helped develop a new policy change for implementing a way by which this treated water may be used. Six Sigma has not been widely implemented in oil and gas industries. This research adopted the Six Sigma methodology through a case study, related to the southern Iraqi oil fields, to investigate different ways by which produced water can be treated. Research results showed that the enormous amount of contaminated PW could be treated by using membrane filtration technology. In addition, a Multi Criteria Decision Making (MCDM) framework is developed and that could be used as an effective tool for decision makers. The developed framework could be used within manufacturing industries, services, educational systems, governmental organizations, and others.M.S.
Masters
Industrial Engineering and Management Systems
Engineering and Computer Science
Industrial Engineering; Quality Systems Engineering