Dissertations / Theses on the topic 'Oil flow measurement'

This thesis describes the development of a novel tomographic imaging system which can measure the concentration and velocity profiles in two-phase oil/gas flows. Two-phase flow measurement is a problem of great strategic and commercial importance to the oil industry. For example, an oilwell seldom produces just oil; there is often a significant quantity of gas and/or water present and it is very important to know how much of each is being produced. Unfortunately, this turns out to be a very demanding: task, particularly when the components have significantly different densities as in oil/gas flows. The fundamental problem with oil/gas flow measurement is that the individual components can arrange themselves in many different ways. This results in many possible concentration and velocity distributions, which in turn, render conventional flow measurement techniques inadequate. The tomographic system overcomes these problems by explicitly deriving the component distributions at two adjacent planes along a pipeline. These two images of the component distributions are then cross correlated on a pixel-by-pixel basis to obtain the velocity profile of the gaseous component. Multiplying the component concentration and velocity profiles yields a measure of the volumetric gas flow rate. The component distributions are obtained using two tomographic capacitance imaging systems. The problems caused by their interference have been examined in detail and this includes extensive electrostatic simulation studies. The field interactions are shown to affect the effective distance between the sensors and this varies with radial position, resulting in an effective separation profile". Numerous component distribution and velocity profile measurements are presented which were obtained from a 3" multi-phase flow loop, with superficial oil velocities ranging from 0.1m/s to 0.8m/s. and superficial gas velocities ranging from 0.05m/s to 0.5m/s. Void fractions range from 5% to 55%. The system is based on a combination of transputer and digital signal processor hardware and can reconstruct images at 180 frames per second. Techniques for real-time image correlation are examined and these, in combination with a number of suggestions for future work, will facilitate the development of a novel, real-time, multi-phase flow measurement system

Dadas as expectativas de grandes descobertas de petróleo no Brasil (que incluem o pré-sal) a recente legislação que regulamenta a medição de vazão de petróleo e gás natural no país - e que faz intenso uso de infra-estrutura laboratorial- está sendo revista. A presente pesquisa de mestrado tem por objetivo desenvolver uma análise crítica envolvendo aspectos técnicos e legais do Regulamento Técnico de Medição de Petróleo e Gás Natural (RTM) instituído pela Portaria Conjunta ANP-INMETRO 001/2000. A motivação institucional para o desenvolvimento da pesquisa origina-se do interesse da Petrobrás em colaborar para o avanço do conhecimento relacionado às tecnologias e aos aspectos legais da medição. E, também, da experiência do autor no setor de contratos da Petrobrás cuja problemática da medição da produção de petróleo e gás natural está sendo revista. O trabalho foi desenvolvido no contexto de recentes descobertas de campos gigantes em águas profundas e ultra-profundas. Após o anúncio dessas novas reservas, agentes econômicos têm pressionado a Agência Nacional de Petróleo (ANP) para revisar e reavaliar o Regulamento Técnico de Medição instituído pela Portaria Conjunta ANP-INMETRO 001/2000. O trabalho seguiu os seguintes preceitos metodológicos (i) estudo de legislações aplicáveis à medição de petróleo e gás de países industrializados; (ii) entrevista com especialistas do INMETRO, ANP, Petrobrás (CENPES, divisão de contratos) e com dirigentes técnicos dos principais laboratórios de medição de vazão de petróleo e gás ern operação no país (IPT, CT-PETRO, CT-GÁS, CONAUT, METROVAL, EMERSON) para avaliar pontos críticos da Portaria Conjunta ANP-INMETRO; (iii) análise da consistência e adequação técnica e jurídica da referida Portaria e (iv) identificar novas demandas e necessidades da indústria de petróleo e gás natural no país. Dentre os resultados da pesquisa destacam-se a identificação e a classificação de aspectos técnicos e legais da Portaria ANP-INMETRO 001/2000 que carecem de revisão. Como conclusão, o trabalho sugere a adaptação da legislação vigente para fazer frente a novos desafios impostos ao setor.
Because of the expectation for further massive oil fmdings in Brazil`s continen tal platform-including the presalt play-, the existing laws which regnlate the oil and natural gás measurement involving intensive use of laboratory infras-tructure are being reviewed. The objective of this M.Sc.`s research project is to assess legal and technical aspects of the Joint Administrative Rule ANP-INMETRO / 001/2000, specifically the Technical Regulation of Oil and Natural Gás Measurement (RTM).The inotivation of this work emerged frorn the anthors own experience at the legal department of Petrobras dealing with custody transfer contracts where measurements of the production of oiland natural gás play a key economic role. Following the announcements of the ultra-deep giant fields, the work was developed in an economic context where agents are pressing the Brazilian Petroleum Agency (ANP) the national oil and gás regulator to review and reassess the applicable Technical Regulation of Measurement (RMO). The project followed four methodological precepts (i) study of applicable laws to the flow measuremeut of oil and gás in developed countries; (ii) interview with experts of INMETRO, ANP, PETOBRAS (CENPES, division of contracts) and technical managers of themain laboratories involved in flow measurements (IPT, CT-PETRO, CTGAS, CONAUT, METROVAL, EMERSON) to ascertain criticai points in the Joint Administrative Rule ANP-INMETRO; (iii) analysis of consistency of legal and technical aspects of the Administrative Rule and (iv) identify new demands and needs of the oil and gás industry in the country. As the main result, the work identified and characterized technical and legal aspects of the legislation related to oil and gás flow measnrements to help reformulate and update the Administrative Rule, ANP-INMETRO 001/2000. In conclusion, the oil and gás legislation conccrning the Technical Regulation and Measurement should be adapted to new exploration challenges.

PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO
O medidor de vazão de fluido multifásico (MM) se desenvolveu impulsionado principalmente pela necessidade da indústria de óleo e gás em medir a vazão da produção dos poços que comumente é composta por petróleo, gás e água. Em outubro de 2015, a Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (ANP) publicou o Regulamento Técnico de Medição de Fluido Multifásico para Apropriação de Petróleo, Gás Natural e Água que apresenta os requisitos através de planos que as empresas operadoras de óleo e gás precisam preparar e submeter para obter a autorização para aplicar o MM na medição para apropriação. Contudo, esse regulamento não especifica a metodologia que deve ser utilizada no denominado plano de verificação de desempenho para avaliar desempenho do MM no campo, cabendo a cada operadora desenvolver a sua metodologia para esse fim e apresentar a ANP. Este trabalho propõe e aplica uma metodologia para verificação de desempenho para MM com resultados de testes realizados em laboratório com fluidos reais e em campo de produção de petróleo e gás. É observado que testes com tempo curto de duração, inferior a 1000 segundos, tendem a gerar incertezas mais elevadas do que testes com longa duração, com mais de 1000 segundos, como os realizados na plataforma. Sendo assim, os resultados de incerteza de medição maiores gerados no laboratório com tempos de integração curtos podem ser considerados mais conservativos que os resultados dos testes realizados na plataforma.
The multiphase flowrate (MM) was driven by the necessity of the oil and gas industry to measure the production flow of the wells that are commonly composed of oil, gas and water. In October 2015, the National Agency for Petroleum, Natural Gas and Biofuels (ANP) published the Technical Regulation for Measurement of Multiphase Fluid for Petroleum, Natural Gas and Water produced, which presents the requirements through plans that oil and gas companies need to prepare and submit for authorization to apply the MM in the measurement for allocation. However, this regulation does not specify the methodology that should be used in the so-called performance verification plan to evaluate the performance of the MM in the field, it being incumbent on each operator to develop its methodology for this purpose and present the ANP. This work proposes and applies a methodology for performance verification for MM with test results performed in the laboratory with real fluids and in oil and gas field. It was observed that short duration tests, below 1000 seconds, tend to generate higher uncertainties than long tests, higher than 1000 seconds, such as those performed on the platform. Thus, the higher measurement uncertainty results generated in the laboratory with short integration times can be considered more conservative than the results of the tests performed in the platform.

Pressure drop and void fraction are important hydro-dynamic aspects for wet gas metering. Among differential pressure drop meters, Venturi meters are the most favoured devices for measuring unprocessed wet gas flows. However, Venturi meters are based on dry gas metering concepts, and various correlation factors have to be applied to the readings, Because the correction factors are flow-regime-dependent and only valid within specified operating flow conditions (preferably homogeneous or quasi-homogeneous flows), preconditioning or mixing devices are required. Electrical capacitance tomography (ECT) has been applied to measure wet gas separation processes. A combination of Venturi and ECT present the strengths of both principles and overcome the respective disadvantages. The combination also gives a possibility for wet gas pressure gradient calculation using void fraction measurement from ECT.

PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO
COORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIOR
PROGRAMA DE SUPORTE À PÓS-GRADUAÇÃO DE INSTS. DE ENSINO
O objetivo desta dissertação é avaliar a influência do teor de água e do fator do medidor na incerteza de malhas fiscais de medição de óleo utilizando medidores ultrassônicos. A motivação deste trabalho advém do fato do Regulamento Técnico de Medição de Petróleo e Gás Natural (RTM) existente limitar quais metodologias podem ser utilizadas para realizar a análise de teor de água e qual a incerteza máxima permitida para a malha de medição na qual esta se insere, porém não define a incerteza desta, havendo o risco de se adotar um dos métodos de análise permitidos e, ainda assim, a incerteza de medição da malha ultrapassar a definida pela legislação. Além disso, o RTM adota um critério de repetibilidade para a validação das calibrações dos medidores ultrassônicos, portanto avalia-se também a influência deste na incerteza da malha. A metodologia utilizada foi o planejamento de experimentos, utilizando superfície de resposta. Os resultados demonstram que é possível simular a influência da incerteza da análise da água e do fator do medidor na incerteza da malha. Por fim, as conclusões demonstram que as médias atualmente encontradas para incerteza do teor de água são adequadas para manter a incerteza da malha dentro da permitida pelo RTM, porém com pouca variação pode-se exceder este limite; a influência da incerteza do fator do medidor foi inferior ou similar à do teor de água e, por fim, sugere-se a adoção de um critério limite de incerteza ao invés de um critério de repetibilidade para os medidores ultrassônicos.
The aim of this dissertation is to evaluate the influence of water content dissolved in crude oil and the meter factor on the uncertainty of the fiscal oil metering using ultrasonic flow meters. The development of this work is motivated by the fact that the Technical Regulation for the Measurement of Oil and Natural Gas (RTM) limits which methodologies can be used for water analysis and what is the maximum permissible uncertainty for the oil flow meter in which it is inserted. However, the RTM doesn t define the uncertainty of the water analysis. There is a risk of adopting one of the permitted methods of analysis and, even so, the measurement uncertainty of the flow meter exceeds the defined by the legislation. In addition, the RTM adopts a repeatability standard when validating the calibration of ultrasonic meters, thus the influence of this on oil uncertainty is also evaluated. The methodology used is the design of experiments and response surface. The results demonstrate that the influence of the water content uncertainty analysis and of the meter factor on the uncertainty of the oil flow meter can be simulated. Finally, the conclusions show that the average currently found for uncertainty of water is adequate to maintain the oil uncertainty within the allowed by the RTM, but small variations may cause this limit to be exceeded. The influence of the meter factor uncertainty was inferior or similar to the water content and, finally, it is suggested the adoption of a standard limit of uncertainty instead of a standard of repeatability for the ultrasonic meters.

CO2 sequestration is a promising strategy to reduce the emissions of CO2 concentration in the atmosphere, to enhance hydrocarbon production, and/or to extract geothermal heat. The target formations can be deep saline aquifers, abandoned or depleted hydrocarbon reservoirs, and/or coal bed seams or even deep oceanic waters. Thus, the potential formations for CO2 sequestration and EOR (enhanced oil recovery) projects can vary broadly in pressure and temperature conditions from deep and cold where CO2 can exist in a liquid state to shallow and warm where CO2 can exist in a gaseous state, and to deep and hot where CO2 can exist in a supercritical state. The injection, transport and displacement of CO2 in these formations involves the flow of CO2 in subsurface rocks which already contain water and/or oil, i.e. multiphase flow occurs. Deepening our understanding about multiphase flow characteristics will help us building models that can predict multiphase flow behaviour, designing sequestration and EOR programmes, and selecting appropriate formations for CO2 sequestration more accurately. However, multiphase flow in porous media is a complex process and mainly governed by the interfacial interactions between the injected CO2, formation water, and formation rock in host formation (e.g. interfacial tension, wettability, capillarity, and mass transfer across the interface), and by the capillary , viscous, buoyant, gravity, diffusive, and inertial forces; some of these forces can be neglected based on the rock-fluid properties and the configuration of the model investigated. The most influential forces are the capillary ones as they are responsible for the entrapment of about 70% of the total oil in place, which is left behind primary and secondary production processes. During CO2 injection in subsurface formations, at early stages, most of the injected CO2 (as a non-wetting phase) will displace the formation water/oil (as a wetting phase) in a drainage immiscible displacement. Later, the formation water/oil will push back the injected CO2 in an imbibition displacement. Generally, the main concern for most of the CO2 sequestration projects is the storage capacity and the security of the target formations, which directly influenced by the dynamic of CO2 flow within these formations. Any change in the state of the injected CO2 as well as the subsurface conditions (e.g. pressure, temperature, injection rate and its duration), properties of the injected and present fluids (e.g. brine composition and concentration, and viscosity and density), and properties of the rock formation (e.g. mineral composition, pore size distribution, porosity, permeability, and wettability) will have a direct impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have a direct influence on the injection, displacement, migration, storage capacity and integrity of CO2. Nevertheless, despite their high importance, investigations have widely overlooked the impact of CO2 the phase as well as the operational conditions on multiphase characteristics during CO2 geo-sequestration and CO2 enhanced oil recovery processes. In this PhD project, unsteady-state drainage and imbibition investigations have been performed under a gaseous, liquid, or supercritical CO2 condition to evaluate the significance of the effects that a number of important parameters (namely CO2 phase, fluid pressure, temperature, salinity, and CO2 injection rate) can have on the multiphase flow characteristics (such as differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The study sheds more light on the impact of capillary and viscous forces on multiphase flow characteristics and shows the conditions when capillary or viscous forces dominate the flow. Up to date, there has been no such experimental data presented in the literature on the potential effects of these parameters on the multiphase flow characteristics when CO2 is injected into a gaseous, liquid, or supercritical state. The first main part of this research deals with gaseous, liquid, and supercritical CO2- water/brine drainage displacements. These displacements have been conducted by injecting CO2 into a water or brine-saturated sandstone core sample under either a gaseous, liquid or supercritical state. The results reveal a moderate to considerable impact of the fluid pressure, temperature, salinity and injection rate on the differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The results show that the extent and the trend of the impact depend significantly on the state of the injected CO2. For gaseous CO2-water drainage displacements, the results showed that the extent of the impact of the experimental temperature and CO2 injection rate on multiphase flow characteristics, i.e. the differential pressure profile, production profile (i.e. cumulative produced volumes), endpoint relative permeability of CO2 (KrCO2) and residual water saturation (Swr) is a function of the associated fluid pressure. This indicates that for formations where CO2 can exist in a gaseous state, fluid pressure has more influence on multiphase flow characteristics in comparison to other parameters investigated. Overall, the increase in fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) caused an increase in the differential pressure. The increase in differential pressure with increasing fluid pressure and injection rate indicate that viscous forces dominate the multi-phase flow. Nevertheless, increasing the differential pressure with temperature indicates that capillary forces dominate the multi-phase flow as viscous forces are expected to decrease with this increasing temperature. Capillary forces have a direct impact on the entry pressure and capillary number. Therefore, reducing the impact of capillary forces with increasing pressure and injection rate can ease the upward migration of CO2 (thereby, affecting the storage capacity and integrity of the sequestered CO2) and enhance displacement efficiency. On the other hand, increasing the impact of the capillary force with increasing temperature can result in a more secure storage of CO2 and a reduction in the displacement efficiency. Nevertheless, the change in pressure and temperature can also have a direct impact on storage capacity and security of CO2 due to their impact on density and hence on buoyancy forces. Thus, in order to decide the extent of change in storage capacity and security of CO2 with the change in the above-investigated parameters, a qualitative study is required to determine the size of the change in both capillary forces and buoyancy forces. The data showed a significant influence of the capillary forces on the pressure and production profiles. The capillary forces produced high oscillations in the pressure and production profiles while the increase in viscous forces impeded the appearance of these oscillations. The appearance and frequency of these oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents. The appearance of the oscillations can increase CO2 residual saturation due to the re-imbibition process accompanied with these oscillations, thereby increasing storage capacity and integrity of the injected CO2. The differential pressure required to open the blocked flow channels during these oscillations can be useful in calculating the largest effective pore diameters and hence the sealing efficiency of the rock. Swr was in ranges of 0.38-0.42 while KrCO2 was found to be less than 0.25 under our experimental conditions. Increasing fluid pressure, temperature, and CO2 injection rate resulted in an increase in the KrCO2, displacement efficiency (i.e. a reduction in the Swr), and cumulative produced volumes. For liquid CO2-water drainage displacements, the increase in fluid pressure (60-70 bar), CO2 injection rate (0.4-1ml/min) and salinity (1% NaCl, 5% NaCl, and 1% CaCl2) generated an increase in the differential pressure; the highest increase occurred with increasing the injection rate and the lowest with increasing the salinity. On the other hand, on the whole, increasing temperature (20-29 °C) led to a reduction in the differential pressure apart from the gradual increase occurred at the end of flooding.

Orientadores: Antonio Carlos Bannwart, Oscar Mauricio Hernandez Rodriguez
Tese (doutorado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências
Made available in DSpace on 2018-08-28T09:34:02Z (GMT). No. of bitstreams: 1 BonillaRiano_Adriana_D.pdf: 7155927 bytes, checksum: 63be57b0a5136f5e783cfb4f870b0189 (MD5) Previous issue date: 2015
Resumo: Neste trabalho, é apresentado o desenvolvimento de uma nova técnica para a medição da espessura do filme de água com alta resolução espacial e temporal em escoamento óleo-água. É proposto o uso de um sistema de medição de capacitância elétrica para medir filmes finos de água na proximidade da parede do tubo. O sistema conta com um sensor planar e foi necessário determinar a melhor geometria via simulações baseadas no Método de Elementos Finitos (FEM) para o caso de escoamento óleo-água. As características comparadas foram a profundidade de penetração do campo elétrico no filme de água, a sensibilidade, a resolução espacial mínima e a resposta quase-linear. Padrões de escoamento óleo-água disperso e anular instável foram estudados numa tubulação vertical de 12 m de comprimento, feita de vidro, com 50,8 milímetros de diâmetro interno. Os fluidos usados foram óleo mineral (com densidade 828 kg/m3 e viscosidade 220 mPas) e água da torneira. O trabalho experimental foi realizado nas instalações de escoamento multifásico do Laboratório de Engenharia Térmica e Fluidos (NETeF) da EESC-USP. Foi medida a espessura média do filme de água usando o sistema capacitivo e uma câmera de vídeo de alta velocidade. Para obter a espessura do filme de água a partir das imagens, foi proposto um algoritmo de pré-processamento e um algoritmo de segmentação que combina vários métodos disponíveis na literatura. Os resultados experimentais do sensor capacitivo mostraram que o sistema pode medir espessuras entre 400 µm e 2200 µm. O escoamento anular instável é caracterizado por grandes flutuações na no sentido do escoamento e na direção do perímetro, e estruturas interfaciais grandes (gotas). Por sua vez, o escoamento disperso tem flutuações menores no sentido do escoamento e na direção do perímetro, e estruturas interfaciais menores (gotículas). Uma estrutura interfacial média no espaço e no tempo é proposta para modelar a interface entre a região próxima à parede do tubo e a região do núcleo, e sua análise foi feita no domínio do tempo e da frequência. Foram estudadas a amplitude, velocidade e o comprimento da estrutura interfacial em cada par transmissor-receptor do sensor. Foi possível estabelecer correlações para a velocidade das estruturas em escoamento de óleo em água
Abstract: The development of a new technique for high spatial and temporal resolution film thickness measurement in oil-water flow is presented. A capacitance measurement system is proposed to measure thin water films near to the wall pipe. A planar sensor was chosen for sensing and some geometries were compared using finite elements method (FEM). The penetration depth, the sensitivity, the minimum spatial resolution (high spatial resolution) and the quasi-linear curve were the analyzed characteristics. Dispersed and unstable-annular oil-water flows patterns were studied in a 12-m long vertical glass pipe, with 50.8 mm of internal diameter, using mineral oil (828 kg/m3 of density and 220 mPa s of viscosity) and tap water. The experimental work was carried out in the multiphase-flow facilities of The Thermal-Fluids Engineering Laboratory (NETeF) of EESC-USP. Experiments with a high-speed video camera and the proposed capacitance system were performed to obtain images of the oil-water flow near the pipe wall. A pre-processing enhancement algorithm and a combined segmentation algorithm are proposed and allowed the measurement of characteristic space and time averaged water film thickness. Experimental results of the capacitive technique showed that the system could measure thickness between 400 µm and 2200 µm. It was possible to recognize and characterize typical behaviors of the two different flow patterns studied. Unstable-annular flow can be described by huge fluctuations on the flow direction and perimeter direction, and big interfacial structures (drops). On the other hand, dispersed flow has tiny fluctuations on the flow direction and perimeter direction, and smaller interfacial structures (droplets). An interfacial structure is suggested in order to model the interface between wall and core regions and it was analyzed in time and frequency domains; amplitude, velocity and wavelength at each pair transmitter-receiver of the sensor were studied. Correlations for the interfacial structure velocity were found for dispersed oil-in-water flow and unstable-annular flow
Doutorado
Explotação
Doutora em Ciências e Engenharia de Petróleo
CAPES

Two phase flow investigations have been undertaken for some time involving either liquid-gas or liquid-liquid flows. In spite of the growing interest in inclined (deviated) oil-water flows, only a small number of experimental data exist. This thesis describes an experimental study into deviated oil-water flows using thermal anemometry and optical probes. Two novel measuring techniques have been designed and tested in a 78mm diameter multiphase flow ioop. The measuring devices are known as the dual probe and the dual split-film probe. The dual probe is a combination of a hot-film anemometer and two optical probes. One of the optical probes was used to simplify the analysis of hot-film signals. The dual split-film probe is similar to the dual probe except that it uses a split-film anemometer instead of a hot-film anemometer. The dual probe and the dual split-film probe are both capable of measuring, locally at the same time, the continuous phase velocity, the dispersed phase velocity and the volume fraction. The results from testing the dual probe were satisfactory except when used to measure the water velocity in deviated flow. The hot-film anemometer was not capable of measuring back flows which can be encountered on the bottom part of pipes. The dual split-film probe was successfully tested in deviated flows and was capable of measuring back flows. Local slip velocities and droplet cut chord length profiles were investigated. It was shown that as the oil volume fraction increases, the slip velocity decreases, for all flow conditions investigated. The droplet cut chord length was seen to vary from 2 - 4mm in vertical flow; however in deviated flow, the droplet cut chord length remained constant at approximately 5mm, in regions where oil was present. As a part of the continuing research into deviated oil-water flows, the data gathered were compared to a two phase model with some success. Both the dual probe and the dual split-film probe are patented by Schiumberger Cambridge Research (Simonian [1991]).

Relative permeabilities for three-phase flow are commonly predicted from two-phase flow measurements using empirical models. These models are usually tested against available steady state data. However, the oil flow is unsteady state during various production stages such as gas injection after water flood. Accurate measurement of oil permeability([subscript ro]) during unsteady tertiary gas flood is necessary to study macroscopic oil displacement rate under micro scale events including double drainage, coalescence and reconnection, bulk flow and film drainage. We measure the three-phase oil relative permeability by conducting unsteady-state drainage experiments in a 0.8m water-wet sandpack. We find that when starting from capillary-trapped oil, k[subscript ro] starts high and decreases with a small change in oil saturation, and shows a strong dependence on both the flow of water and the water saturation, contrary to most models. The observed flow coupling between water and oil is stronger in three-phase flow than two-phase flow, and cannot be observed in steady-state measurements. The results suggest that the oil is transported through moving gas/oil/water interfaces (form drag) or momentum transport across stationary interfaces (friction drag). We present a simple model of friction drag which compares favorably to the experimental data. We also solve the creeping flow approximation of the Navier-Stokes equation for stable wetting and intermediate layers in the corner of angular capillaries by using a continuity boundary condition at the layer interface. We find significant coupling between the condensed phases and calculate the generalized mobilities by solving co-current and counter-current flow of wetting and intermediate layers. Finally, we present a simple heuristic model for the generalized mobilities as a function of the geometry and viscosity ratio. To identify the key parameter controlling the measured excess oil flow during tertiary gasflood, we also conduct simultaneous water-gas flood tests where we control water relative permeability and let water saturation develop naturally. The measured data and pore scale calculations indicate that viscous coupling can not explain completely the observed flow coupling between oil and water. We conclude that the rate of water saturation decrease, which controls the pore scale mechanisms including double drainage, reconnection, and film drainage significantly influences the rate of oil drainage during tertiary gas flood. Finally, we present a simple heuristic model for oil relative permeability during tertiary gas flood, and also explain how Stone I and saturation-weighted interpolation should be used to predict the permeability of mobilized oil during transient tertiary gasflood.
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Many of the world's oil fields and aquifers are found in carbonate strata. Some of these formations contain vugs or cavities several centimeters in size. Flow of fluids through such rocks depends strongly upon the spatial distribution and connectivity of the vugs. Enhanced oil recovery processes such as enriched gas drives and groundwater remediation efforts like soil venting operations depend on the amount of hydrodynamic dispersion of such rocks. Selecting a representative scale to measure permeability and dispersivity in such rocks can be crucial because the connected vug lengths can be longer than typical core diameters. Large touching vug (centimeter-scale), Cretaceous carbonate rocks from an exposed rudist (caprinid) reef buildup at the Pipe Creek Outcrop in Central Texas were studied at three different scales. Single-phase airflow and gas-tracer experiments were conducted on 2.5 in. diameter by 5 in. long cores (core-scale) and 5- to 10-ft-radius well tests (field-scale). Zhang et al. (2005) studied a 10 in. diameter by 14 in. high sample (bench-scale). Vertical permeability in the bench-scale varied from 100 darcies to 10 md and in the core-scale averaged 2.5 darcies. The field-scale permeability was estimated to be 500 md from steady state airflow and pressure transient tests. In the bench and core scales a connected path of vugs dominates flow and tracer concentration breakthrough profile. Tracer transport showed immediate breakthrough times and a long tail in the tracer concentrations characterized by multiple plateaus in concentrations. Neither flow nor tracer transport can be explained at these scales by the standard continuum equations (Darcy’s law or 1D convection dispersion equation). However, interpreting field-scale measurements with standard continuum equations suggested that a strongly connected path of vugs did not extend past a few feet. In particular, the tracer experiment in the field scale can be modeled accurately using an equivalent homogeneous porous medium with a dispersivity of 0.5 ft. In our measurements, permeability decreased with scale, while vug connectivity and multi-scale effects associated with vug connectivity decreased with increasing scale. We concluded that approximately 5 ft could be considered the representative scale for the large-touching-vug carbonate rocks at the Pipe Creek Outcrop. The major contribution of this research is the introduction of an integrated, multi-scale, experimental approach to understanding fluid flow in carbonate rocks with interconnected networks of vugs too large to be adequately characterized in core samples alone.
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碩士
國立雲林科技大學
機械工程系碩士班
93
In air-conditioning systems, a small amount of lubricating oil is utilized to lubricate the sliding parts and sealing the compressor. Although the lubricant increases the life of compressor, its solubility in pure refrigerant would significantly affect the thermodynamic properties of theses refrigerants, and hence, would considerably affect performance of the system components. For air-conditioners, use of U-type wavy tubes is very common. As discussed in the literature review, a number of researchers had studied the effects of oil-refrigerant evaporation/condensation heat transfer, and a few investigations had reported the influence of oil on the refrigerant pressure drop in straight tubes. However, very limited studies were reported for the evaluation of refrigerant-oil two-phase heat transfer in U bends, and especially no studies were found to investigate the effect of lubricant on HFC refrigerant pressure drop in small U-type wavy tubes This study presents single-phase and two-phase pressure drop data with oil concentration C = 0, 1, 3 and 5% in a copper wavy tube having an inner diameter of 5.07 mm and a curvature radius of 13.15 mm. The wavy tube of two-phase pressure drop data with oil concentration for C = 1% ~ 5% and the pure refrigerant data ratio about to 0.8and 1.0 at the same mass flux, respectively. However, the effect of oil concentration on friction factor is negligible based on the mixture properties (density and viscosity). The ratio between two-phase pressure gradients at the U-bend and the straight tube is about 3. This ratio is increased with oil concentration, however, the data are scattering due to the variations of vapor quality and mass flux. The oil effect on two-phase pressure drop is more significant at high vapor quality because the oil concentration in liquid mixture is increased with vapor quality. The frictional two-phase multiplier can be fairly correlated by using the Chisholm correlation.In vertical, the void fraction correlated by using the Baroczy and Yashar et al. correlation .More data are needed for obtaining a new correlation.

This dissertation implements three-dimensional numerical simulation models to interpret formation-tester measurements acquired at arbitrary angles of wellbore deviation. Simulations include the dynamic effects of mud-filtrate invasion and multi-phase flow. Likewise, they explicitly consider the asymmetric spatial distribution of water-base and oil-base mud filtrate in the near-wellbore region due to the interplay of viscous, gravity, and capillary forces. Specific problems considered by the dissertation are: (a) estimation of permeability from formation-tester measurements (pressure and fractional flow) affected by multi-phase flow and mud-filtrate invasion, (b) quantification of the spatial zone of response of transient measurements of pressure and fractional flow rate, (c) prediction of fluid-cleanup times during sampling operations in vertical and deviated wells, (d) joint inversion of formation-tester and resistivity measurements to estimate initial water saturation and permeability of multi-layer models, and (e) estimation of saturation-dependent relative permeability and capillary pressure using selective measurement weighting and Design-of-Experiment (DoE) methods to secure a reliable initial guess for nonlinear inversion. Using realistic tool and formation configurations, field measurements validate the reliability of the proposed methods. In one example, multi-layer rock formations are modeled using electrofacies derived from nuclear magnetic resonance logs, thereby reducing the number of unknown layer permeability values from 22 to 6. In the same example, non-uniqueness in the estimation of permeability is reduced with the quantitative integration of resistivity and formation-tester measurements. A second field example undertakes the estimation of permeability by history matching both pressure and gas-oil ratio (GOR) measurements acquired with a focused-sampling probe in a 27° deviated well. Because the latter measurements are affected by partial miscibility between oil-base mud and in-situ oil, Equation-of-State (EOS) simulations are used to account for variations of fluid viscosity, fluid compressibility, fluid density, and GOR during the processes of invasion and fluid pumpout. Results indicate that gravity-segregation and capillary-pressure effects become significant with increasing angles of wellbore deviation. If not accounted for, such effects could substantially degrade the estimation of permeability. Synthetic and field examples confirm that standard formation-tester interpretation techniques based on single-phase analytical solutions lead to biased estimations of permeability, especially in deviated wells or when complete fluid cleanup is not achieved during sampling. In addition, it is found that gravity-segregated invaded formations strongly affect predictions of fluid sampling time. Reliable and accurate estimations of petrophysical properties are only possible when both the angle of wellbore deviation and the process of mud-filtrate invasion are included in the interpretation methods.
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Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid.
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