In recent years, the upstream oil and gas industry has dealt with some of the most challenging metering applications. One of these is the measurement of water percentage at the point of allocation. It is an essential requirement when test separators or the newly developed full multiphase meters are utilized for oil well production testing. Water-cut can be obtained from measurement of differential pressure, capacitance/conductance, gamma rays absorption, absorption of infrared light, coriolis mass measurement, or microwave permittivity. The use of microwave permittivity has been shown to be very effective with the added benefit of not requiring a nuclear source, as is the case with a gamma ray densitometers. A common problem encountered in oil well production testing is that of gas “carry-under” into the liquid stream exiting the test separator. This results in a trace amount of gas entering the water-cut meter, producing errors in the water-cut reading. Gas carry-under may be caused by high liquid viscosity, improper separator operation, or poor separator design. Gas carry-under is believed to be one of the major causes of large allocation factors in oil and gas operations. Problems in clearly defining the three-phase stream as to flow regime and actual gas bubble size have been described in the technical literature. Pertinent references are discussed and compared. The issues in trying to perform such tests in the laboratory and the correlation of the data are disclosed and the difficulties in trying to correlate the effects of the entrained gas are described. Field testing and experience by at least one manufacturer of equipment has verified the effect of entrained gas, but little quantitative data relating gas-cut to increased error of measurement has been published. The objective of this work was to investigate the performance of a microwave water-cut analyzer under three-phase flow conditions to determine the impact of the presence of gas in the liquid stream. Experiments were performed that investigated the effects of entrained gas on a commercial water-cut analyzer. These tests were conducted at the Texas A&M Tommie E. Lohman Fluid Measurement Laboratory at low pressure conditions (< 40 psig). The test fluids were air, water and two types of oil: mineral oil and hydraulic oil. These experiments investigated oil continuous emulsion conditions with the Gas Volume Fraction (GVF) ranging from 0-25% and the water-cut ranging from 5-30%. Liquid flow rates were between 500-3,700 bbl/day. A 2-inch water-cut full range meter was utilized for these tests. The error in water-cut was seen to increase with increasing GVF ranging from 0% to 25%. However, the measurement remained stable over the entire range of tests. A correction was developed to correct water-cut meter readings based on the amount of gas in the liquid stream.

In recent years, the upstream oil and gas industry has dealt with some of the most challenging metering applications. One of these is the measurement of water percentage at the point of allocation. It is an essential requirement when test separators or the newly developed full multiphase meters are utilized for oil well production testing. Water-cut can be obtained from measurement of differential pressure, capacitance/conductance, gamma rays absorption, absorption of infrared light, coriolis mass measurement, or microwave permittivity. The use of microwave permittivity has been shown to be very effective with the added benefit of not requiring a nuclear source, as is the case with a gamma ray densitometers. A common problem encountered in oil well production testing is that of gas “carry-under” into the liquid stream exiting the test separator. This results in a trace amount of gas entering the water-cut meter, producing errors in the water-cut reading. Gas carry-under may be caused by high liquid viscosity, improper separator operation, or poor separator design. Gas carry-under is believed to be one of the major causes of large allocation factors in oil and gas operations. Problems in clearly defining the three-phase stream as to flow regime and actual gas bubble size have been described in the technical literature. Pertinent references are discussed and compared. The issues in trying to perform such tests in the laboratory and the correlation of the data are disclosed and the difficulties in trying to correlate the effects of the entrained gas are described. Field testing and experience by at least one manufacturer of equipment has verified the effect of entrained gas, but little quantitative data relating gas-cut to increased error of measurement has been published. The objective of this work was to investigate the performance of a microwave water-cut analyzer under three-phase flow conditions to determine the impact of the presence of gas in the liquid stream. Experiments were performed that investigated the effects of entrained gas on a commercial water-cut analyzer. These tests were conducted at the Texas A&M Tommie E. Lohman Fluid Measurement Laboratory at low pressure conditions (< 40 psig). The test fluids were air, water and two types of oil: mineral oil and hydraulic oil. These experiments investigated oil continuous emulsion conditions with the Gas Volume Fraction (GVF) ranging from 0-25% and the water-cut ranging from 5-30%. Liquid flow rates were between 500-3,700 bbl/day. A 2-inch water-cut full range meter was utilized for these tests. The error in water-cut was seen to increase with increasing GVF ranging from 0% to 25%. However, the measurement remained stable over the entire range of tests. A correction was developed to correct water-cut meter readings based on the amount of gas in the liquid stream.

Offshore production fluids from the reservoir are often transported in pipelines from the wellheads to the platform and from the platform to process facilities. At low flow velocity water, sand or liquids like condensate could settle at the bottom of pipelines that may lead to grave implications for flow assurance. During shutdown the settled heavy liquid (e.g. water), could result in corrosion in pipelines, while following restart stages the settled water could form water plugs that could damage equipment, while settled sand could also form a blockage that needs to be purged. Furthermore, there is a requirement to know the quantity of water and base sediment for fiscal metering and custody transfer purposes. A series of experiments were carried out to observe low water cut in oil and water flows in four inch diameter pipeline. Similarly low sand concentrations in water and sand, water, air and sand flows were observed in two inch diameter pipelines. Conductive film thickness sensors were used to ascertain structural velocities, height and dense phase fractions. Comparisons are made between two cases in order to gain better understanding of the behaviours and dispersal process of low loading denser phase in multiphase flows. The arrangement enabled production of flow regime maps for low water cut oil and water flow, as well as water sand and water, air and sand flows, structural velocities and denser phase removal velocities were also ascertained. Actual in-situ liquid velocities were obtained experimentally. A novel detection of sand in water and water and sand flows was produced. The experimentally obtained film thickness was in agreement with two fluid model predictions. Thus, confirming use of conductive sensors for dense phase classification, film thickness, velocity and holdup measurements in pipelines.

Depleting oil reserves and fluctuating oil prices have necessitated to increase the efficiency of oil production process. This thesis is focused on developing low-cost sensors, which can increase oil production efficiency through real-time monitoring of oil wells and help in safe transport of oil products from the wells to the refineries. Produced fluid from an oil well is a complex mixture of oil, water and gases, which needs to be quantified for various strategic and operational decisions. For many years, test separators have been used to separate oil, water and gases into three separate streams and then to analyse them individually. However, test separators are being replaced by multiphase flow meters (MPFM) which can analyse the complex mixture of oil, water and gas without separating it. However, existing MPFMs are either intrusive or require fluid mixing before the sensing stage. In contrast to existing techniques, first part of this thesis presents a microwave sensor, which can measure water fraction in oil in a non-intrusive way without requiring it to be mixed. Gas fraction sensing can also be performed using the same microwave sensor, which is an on-going work. The sensor operates on dielectric measurement principles and comprises a microstrip T-resonator that has been optimized for a 3D pipe surface. Certain locations on an oil field have limited available space, for which we have also presented a compact version of the microwave water-fraction sensor in this thesis. In this version, metallic housing of the sensor has been used to function as a ground plane for the coaxially located spiral resonator. This housing also protects the sensor from environmental effects. In addition to the efficient production of oil, its safe transport is also a concern for the industry. It is physically impossible to inspect a network of thousands of kilometres of pipelines manually. The existing leak detectors suffer from low sensitivity, high false alarms and dependence on environmental effects. In the last part of this thesis, we present a flexible ringresonator based leak detector, which can be clamped at vulnerable locations along the pipeline for early leak detection.

Efficient oil production and refining processes require the precise measurement of water content in oil (i.e., water-cut) which is extracted out of a production well as a byproduct. Traditional water-cut (WC) laboratory measurements are precise, but are incapable of providing real-time information, while recently reported in-line WC sensors (both in research and industry) are usually incapable of sensing the full WC range (0 – 100 %), are bulky, expensive and non-scalable for the variety of pipe sizes used in the oil industry. This work presents a novel implementation of a planar microwave T-resonator for fully non-intrusive in situ WC sensing over the full range of operation, i.e., 0 – 100 %. As opposed to non-planar resonators, the choice of a planar resonator has enabled its direct implementation on the pipe surface using low cost fabrication methods. WC sensors make use of series resonance introduced by a λ/4 open shunt stub placed in the middle of a microstrip line. The detection mechanism is based on the measurement of the T-resonator’s resonance frequency, which varies with the relative percentage of oil and water (due to the difference in their dielectric properties). In order to implement the planar T-resonator based sensor on the curved surface of the pipe, a novel approach of utilizing two ground planes is proposed in this work. The innovative use of dual ground planes makes this sensor scalable to a wide range of pipe sizes present in the oil industry. The design and optimization of this sensor was performed in an electromagnetic Finite Element Method (FEM) solver, i.e., High Frequency Structural Simulator (HFSS) and the dielectric properties of oil, water and their emulsions of different WCs used in the simulation model were measured using a SPEAG-dielectric assessment kit (DAK-12). The simulation results were validated through characterization of fabricated prototypes. Initial rapid prototyping was completed using copper tape, after which a novel reusable 3D-printed mask based fabrication was also successfully implemented, which would resemble screen printing if it were to be implemented in 3D. In order to verify the design’s applicability for the actual scenario of oil wells, where an oil/water mixture is flowing through the pipes, a basic flow loop was constructed in the IMPACT laboratory at KAUST. The dynamic measurements in the flow loop showed that the WC sensor design is also equally applicable for flowing mixtures. The proposed design is capable of sensing the WC with a fine resolution due to its wide sensing range, in the 80 – 190 MHz frequency band. The experimental results for these low cost and conformal WC sensors are promising, and further characterization and optimization of these sensors according to oil field conditions will enable their widespread use in the oil industry.

Laser absorption spectroscopy has been a valuable technique for sensitive, non-intrusive, in-situ detection of gaseous and liquid phase target species. The infrared spectral region is specifically attractive as it provides opportunities for selective sensing of a multitude of species in various applications. This thesis explores techniques for interference-free sensing in the infrared region for environmental, combustion, and petrochemical applications. A mid-infrared laser-based sensor was designed to detect trace amounts of benzene using off-axis cavity-enhanced absorption spectroscopy and a multidimensional linear regression algorithm. This sensor achieved unprecedented detection limits, making it ideal for environmental and occupational pollution monitoring. Moreover, wavelength tuning and deep neural networks were employed to differentiate between the broadband similar-shaped absorbance spectra of benzene, toluene, ethylbenzene, and xylene isomers. Benzene sensing was enhanced by recent advancement in semiconductor laser technology, which enabled access to the long wavelength mid-infrared region through commercial distributed feedback quantum cascade lasers. The strongest benzene absorbance band in the infrared is near 14.84 μm, and thus was probed for sensitive benzene detection. Wavelength tuning with multidimensional linear regression were employed to selectively measure benzene, carbon dioxide, and acetylene. Cepstral analysis and wavelength tuning were used to develop a selective sensor for fugitive methane emissions. The sensor was proved to be insensitive to baseline laser intensity imperfections and spectral interference from other present species. In combustion studies, it is desirable to have a diagnostic technique that can detect multiple species simultaneously with high sensitivity, selectivity, and fast time response to validate and improve chemical kinetic mechanisms. A mid-infrared laser sensor was developed for selective and sensitive benzene, toluene, ethylbenzene, and xylenes detection in high-temperature shock tube experiments using deep neural networks. The laser was tuned near 3.3 μm, and an off-axis cavity-enhanced absorption spectroscopy setup was used to enable trace detection. Finally, a novel near-infrared laser-based sensor was developed for water-cut sensing in oil-water flow. The sensor was shown to be immune to the presence of salt and sand in the flow and to temperature variations over 25-60°C. This technique has significant advantages for well and reservoir management, where highly accurate water-cut measurements are required.

Heavy oil production has drawn more and more attention in petroleum industry. The amount of heavy oil in the world is twice more than the conventional oil (low viscosity), which has been consumed rapidly from the past. The understanding of flow patterns and pressure losses in multiphase flow with high viscosity oil are vital to assist the design of transportation pipeline. This thesis involves experimental investigation of two phase and three phase flows under high oil viscosity conditions (up to 17000cP) in horizontal pipelines. The multiphase (oil/water/solid/gas) facility was designed and constructed at Cranfield University and consists of 6m long horizontal pipeline of 0.026m diameter along with instrumentations. The principal objectives of the work were to study the effect of viscosity, water cut, temperature variance, and flow conditions on flow patterns and pressure drops for (oil/gas and oil/water) two phase flows; to compare the measured flow parameters and phase distribution with those predicted from models found in the literature for two phase flows; and to conduct an experimental study of gas injection effect on pressure gradient in (oil/water/gas) three phase flow. Due to the nature of heavy oil reservoirs, sand is associated with oil/water mixture when extracted; therefore sand concentration effect on pressure drop in (oil/water/sand) three phase flow is also examined. For oil-air flow, a smooth oil coating was observed in the film region of slug flow, while a ripple structure of oil coating film was found at higher superficial air velocity for slug flow regime and annular flow regime. The ripple structure was believed to increase the effective roughness of the pipe wall, which resulted in higher pressure gradients. The pressure drop correlations from Beggs and Brill (1973) and Dukler et al. (1964) were used to compare with experimental pressure gradients for oil/air flow. It was found that these correlations failed to predict the pressure gradients for heavy oil/air flows in this work. Several new heavy oil/water flow patterns were named and categorized based on observations. Though the heavy oil viscosity is an essential parameter for oil continuous phase flow on pressure drop, it had no significant effect beyond Water Assist Flow (WAF) condition, as a threshold was found for water cut with fixed superficial oil velocity. The transition criterion by McKibben et al. (2000b) for WAF was found to be able to predict this threshold reasonably well. Core Annular Flow (CAF) models were found to greatly under predict the pressure gradients mainly due to the coating (oil fouling) effect associated with this study. A new coating coefficient was introduced to models presented by Bannwart (2001) and Rodriguez et al (2009). The addition of solid in the mixed flow led to minor increase in the pressure gradient when the particles were moving with the flow. However, higher sand concentration in the system led to higher pressure gradient values. The addition of gaseous phase to the oil/water flow was more complex. The gaseous injection was beneficial toward reducing the pressure gradient when introduced in oil continuous phase only at very low water cuts.

O objetivo desta pesquisa é avaliar o potencial de ocorrência de hidrocarbonetos utilizando uma abordagem simplificada para reservatórios de arenito com dados de dois campos petrolíferos. Inclui a modificação de equações tradicionais para os parâmetros relevantes objetivando ajudar a fornecer expressões alternativas para auxiliar na previsão das unidades de fluxo (hidráulicas) dos reservatórios, transmissibilidade e recuperação primária no Bloco de Petróleo de Ritchie e no Campo de Petróleo e Gás de Osland, ambos situados no Delta do Niger, Nigéria. Também envolve a estimativa dos volumes recuperáveis de hidrocarbonetos com os cortes d´água (Water Cut - Cw), o uso de correlações de tempo/profundidade corretas, análise de velocidade aprimorada para petrofísica e interpretações sísmicas envolvendo a recomendação dos pontos para localização de poços de desenvolvimento no Campo de Petróleo e Gás Osland. No geral, quatro equações tradicionais de permeabilidade (Tixier, Timur, Coates e Coates e Danio\'s) foram modificadas para a análise comparativa e previsão da transmissibilidade dos reservatórios selecionados para a recuperação primária de hidrocarbonetos. Da mesma forma, a equação da Schlumberger para as equações de cálculo do índice de fluido livre (Free Fluid Index - FFI), Tiab e Donaldson para o indicador de zona de fluxo (Flow Zone Indicator - FZI) e índice de qualidade do reservatório (Reservoir Quality Index - RQI) foram redefinidas e incorporadas para auxiliar nas avaliações da unidade de fluxo. Além disso, as equações da Schlumberger para a permeabilidade relativa de fluidos também foram modificadas e utilizadas para a predição da Cw associada. Os resultados indicam reservatórios com boas unidades de vazão e taxas de recuperação. Os volumes de Cw nos reservatórios avaliados estão dentro das taxas aceitáveis e permitiram, também, a identificação de outras profundidades prováveis e a recomendação de áreas de drenagem. A utlização de dados de perfilagem de poços em conjunto com os dados sísmicos (Well to Seismic tie - W-ST) ajudou a reduzir a dúvida sobre a espessora econômica (Pay Thickness - Pt) e a área de drenagem (Drainage Area - Ad). Modelos, em forma de simples equações e gráficos, foram sugeridos para a avaliação de reservatórios dentro de unidades de arenito. Com isso, o trabalho penoso no uso de equações tradicionais foi contornado. Desta forma, os erros computacionais que se somam quando se utliza uma série de equações antes das unidades de fluxo serem avaliadas foram evitados. Portanto, acredita-se que os métodos aqui adotados tenham minimizado o risco e a incerteza que acompanham as avaliações da unidade de fluxo, assim como as estimativas de volumes. Recomenda-se que um geólogo com experiência em geofísica ou mesmo um geofísico deve estar sempre envolvido em interpretações sísmicas e petrofísicas. Isso também contribuirá para a redução de riscos e incertezas. / The aim of this research is to evaluate the hydrocarbon potential using a simplified approach in the sandstone reservoirs of the fields within the two case studies. It includes the modification of some traditional equations for the relevant parameters to help provide alternative expressions to aid the prediction of the reservoirs flow (hydraulic) units, transmissibility and primary recovery in Ritchies Oil Block and Osland Oil and Gas Field. It also involves the estimation of the recoverable volumes of hydrocarbons with the associated water cuts (Cw), and the use of correct time/depth correlations and enhanced velocity analysis for petrophysics and seismic interpretations involving the recommendation of the points for siting developmental wells in Osland Oil and Gas Field. Overall, four traditional equations of permeability (Tixiers, Timurs, Coates and Coates and Denoos) were modified for the comparative analysis and prediction of the selected reservoirs transmissibility and primary hydrocarbon recovery. Similarly, the Schlumbergers equation for the free fluid index (FFI), the Tiab, and Donaldsons equations for Flow zone indicator (FZI) and reservoir quality index (RQI) were redefined and engaged to aid the flow units evaluations. In addition, the Schlumbergers equations for fluids relative permeability were also modified and engaged for the prediction of the associated Cw. The results indicate reservoirs with good flow units and rates of recoveries. The volumes of Cw in the evaluated reservoirs are within the acceptable rates and other probable depths and drainage areas were recommended. Well to seismic tie (W-ST) aided to reduce the doubt regarding pay thickness (Pt) and drainages area (Ad). Models, in form of equations and handy charts, were suggested for the evaluation of reservoirs within sandstone units. The drudgery in the use of tradition equations was bypassed. The computational errors that may come with the calculation of a range of equations before flow units are evaluated were avoided. The methods adopted herein are believed to have minimised risk and uncertainty that comes with the flow unit evaluations and volumes estimations. It is supported herein that a geologist upskilled in geophysics or a geophysicist unskilled in geology should always be engaged in seismic and petrophysical interpretations. This will also contribute to risk and uncertainty reduction.