Typescript (photocopy). / Digitized by Kansas Correctional Industries

Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on Dec. 17, 2007). Includes bibliographical references (p. 187-197).

Thesis (MTech (Chemical Engineering))--Cape Peninsula University of Technology, 2016. / Due to the rising cost involve with bringing new fields on stream, of producing residual crude from matured fields, and the significant enhancement in oil recovery provided when compared to conventional water-flooding, increasing attention is being given to chemical flooding technologies. This is particular of interest in mature fields that had previously undergone water flooding. These methods entail injecting chemicals such as surfactant, alkali, and polymer often in mixture into reservoirs to improve oil recovery. In this study a sulfonated surfactant was produced from cheap waste vegetable oils and its performance was assessed in terms of thermal stability at reservoir conditions, adsorption on different reservoir materials, gas chromatography characterization and a limited interfacial tension measurement to evaluate its ability to improve the recovery of crude oil. Waste vegetable oils have great potential as a sustainable and low cost feedstock as well as its low toxicity.

Typescript (photocopy). / Digitized by Kansas Correctional Industries

A thesis Submitted to the School of Chemical and Metallurgical Engineering, Faculty of Engineering and the Built Environment, University of the Witwatersrand, Johannesburg, in fulfillment of the requirements for the degree of Doctor of Philosophy Johannesburg, 2016 / Wettability of a porous reservoir rock is an important factor that affects oil recovery during waterflooding. It is recognized as being important for multiphase properties. Understanding the variation of these properties in the field, due to wettability trends and different pore structures, is very critical for designing efficient and reliable processes and projects for enhanced hydrocarbon recovery. After primary drainage the reservoir wettability changes: if it was oil-wet initially, it gradually changes to water-wet during waterflooding. This change in reservoir wettability towards water-wet will reduce the residual oil saturation and improve the oil displacement efficiency. However, knowledge of the constitutive relationship between the pore scale descriptors of transport in the porous system is required to adequately describe wettability trend and its impact on oil recovery, particularly during waterflooding. In this work, the petrophysical properties that define fluid flow in the Agbada, Nigeria sandstone reservoir were determined using conventional experimental and x-ray CT scanning methods. Experimentally measured average porosity is 0.28, average permeability is 1699 mD, while the initial and irreducible water saturation is 0.22. Permeability in the x, y and z directions, ranging from 50 to 200 mD, were calculated from the pore network extracted from the Agbada sandstone rock. Results obtained from the Amott-Harvey wettability measurement method indicate that the reservoir is strongly water-wet, with Amott-Harvey index of about 0.9. The cross-over between the water and oil relative permeabilities occurred at saturations of the samples above 0.5, giving an indication of strong water-wetness. The work summarizes the mechanism of wettability alteration and characterizes the performance of the reservoir during waterflooding from injecting water, and relates the residual oil saturation, relative permeability and volumes of water injected to wettability and its effects on oil recovery. Waterflood oil recovery is computed using the Buckley-Leverett method based on the reservoir rock and fluid properties. Computed waterflood oil recovery using this method was about 60% of the oil initially in place. Plots of spontaneous imbibition rate show that the injection rate for optimal oil recovery is 40 bbls of injected water per day. At this rate, both the mobility and shock front mobility ratios are less than 1, leading to a stable flood front and absence of viscous fingering. Waterflooding is by far the most widely applied method of improved oil recovery over the years with good results in conventional and unconventional (tight oil) reservoirs It is relatively simple and cost effective: abundance and availability of water. Waterflood oil recovery factor is affected by internal and external factors. The placement of the injection and production wells, for example, impacts on the effectiveness of the waterflooding process. I considered the placement of the wells in a five-spot pattern as elements of an unbounded double periodic array of wells and assumed the reservoir to be homogeneous, infinite and isotropic, with constant porosity and permeability. Both fluids are treated as having slight but constant compressibility and their flow governed by Darcy’s law. The average pressure in the reservoir satisfies quasi-static flow or diffusion equation. I then assumed piston-like displacement of oil by injected water that takes account of viscosity diffence between both fluids and proposed a model based on the theory of elliptic functions, in particular Weierstrass p-functions functions. Oil-water contact movement, dimensionless time for water breakthrough at the production well, areal sweep and average reservoir pressures were modeled. The model was tested using Wolfram Mathematica 10 software and the results are promising. The thesis has therefore established that the Agbada sandstone reservoir is strongly water-wet and that waterflooding is a viable option for enhanced oil recovery from the reservoir. / MT2016

Os dados utilizados no estudo de reservatórios de petróleo são obtidos a partir de testemunhos de sonda, perfis de poços e registros sísmicos e como tais apresentam diferentes escalas de amostragem. A geoestatística multivariada proporciona uma maneira de integrar esses dados permitindo estimar uma variável escassamente amostrada com base nas suas próprias informações e naquelas de uma variável densamente amostrada. Nesse estudo, utilizou-se a cokrigagem ordinária, a cokrigagem colocalizada e a krigagem com deriva externa para coestimar a porosidade no Campo de Namorado a partir da impedância acústica. As co-estimativas obtidas por cada método foram comparadas quanto à correlação com a porosidade amostral, à reprodução das estatísticas descritivas amostrais e à correlação com a impedância acústica. A correlação entre os valores co-estimados e amostrais de porosidade é de aproximadamente 0.7, diminuindo apenas ao se utilizar a cokrigagem ordinária aplicada a dados heterotópicos. Quanto à reprodução das estatísticas amostrais, a média, mediana e o desvio padrão das co-estimativas são sempre menores que os respectivos amostrais. Os valores de máximo e mínimo das co-estimativas revelam ocorrência do efeito de suavização, exceto ao se utilizar cokrigagem colocalizada com Modelo de Markov. As co-estimativas obtidas por esse método correlacionaram-se melhor com as medidas de impedância acústica, mas essa correlação é muito baixa e inferior à obtida a partir dos dados amostrais. Adicionalmente, foi feita a caracterização petrofísica das fácies litológicas descritas para esse campo, elaborado o modelo tridimensional de fácies e calculado o volume poroso do reservatório. A fácies 1 constitui o reservatório de melhor qualidade, pois apresenta maiores valores de porosidade e permeabilidade. A fácies 2 representa um reservatório de qualidade inferior por ser porosa e menos permeável que a primeira. As fácies 3 e 4 são rochas capeadoras devido aos seus baixos valores de porosidade e permeabilidade. No modelo faciológico, as fácies 1, 2 e 4 ocorrem intercaladas, enquanto a fácies 3 apresenta distribuição mais ampla e contínua. Quanto aos volumes porosos, os maiores valores foram obtidos para os reservatórios definidos com base nos modelos de porosidade estimados pela cokrigagem colocalizada com utilização do Modelo de Markov e pela cokrigagem ordinária a partir dos dados heterotópicos. / Data used for studying petroleum reservoirs are obtained through drill core, well logs, seismic records and, as a consequence, they present different sampling scales. Multivariate geostatistics is a manner of integrating these data in order to co-estimate a poorly sampled variable based not only on its own information but also on a densely sampled variable. In this study, ordinary cokriging, collocated cokriging and kriging with external drift were applied to co-estimate porosity in the Namorado Oil Field based on measures of acoustic impedance. Correlation coefficients between co-estimates and sample porosity values, sample statistics and correlation coefficients between co-estimates and acoustic impedance measures have been examined. Correlation between co-estimated and sample values of porosity is about 0.7. Lower correlation was obtained by ordinary cokriging applied to heterotopic data. Co-estimates statistics such as mean, median and standard deviation are always lower than their equivalent sample statistics. Values of maximum and minimum indicate that co-estimates were smoothed except for collocated cokriging with Markov Chain results. Co-estimates obtained by this last method also presented the best correlation to acoustic impedance measures, though this correlation is very low and lower than that calculated through sample data. In addition to that, it was done petrophysical characterization of lithologic facies described for this oil field, elaborated 3D facies model and calculated the porous volume of the reservoir. Facies 1 constitutes a high quality reservoir rock since it presents the highest values of porosity and permeability. Facies 2 represents a inferior quality reservoir rock because it is porous but less permeable than the first. Facies 3 and 4 are seal rock for their low porosity and permeability values. In 3D model, facies 1, 2 and 4 are intercalated to each other while facies 3 presents a wider and more continuous distribution. Finally, the porous volumes were higher for the reservoirs defined based on porosity models estimated by collocated cokriging with Markov Chain and ordinary cokriging applied to heterotopic data.

Os dados utilizados no estudo de reservatórios de petróleo são obtidos a partir de testemunhos de sonda, perfis de poços e registros sísmicos e como tais apresentam diferentes escalas de amostragem. A geoestatística multivariada proporciona uma maneira de integrar esses dados permitindo estimar uma variável escassamente amostrada com base nas suas próprias informações e naquelas de uma variável densamente amostrada. Nesse estudo, utilizou-se a cokrigagem ordinária, a cokrigagem colocalizada e a krigagem com deriva externa para coestimar a porosidade no Campo de Namorado a partir da impedância acústica. As co-estimativas obtidas por cada método foram comparadas quanto à correlação com a porosidade amostral, à reprodução das estatísticas descritivas amostrais e à correlação com a impedância acústica. A correlação entre os valores co-estimados e amostrais de porosidade é de aproximadamente 0.7, diminuindo apenas ao se utilizar a cokrigagem ordinária aplicada a dados heterotópicos. Quanto à reprodução das estatísticas amostrais, a média, mediana e o desvio padrão das co-estimativas são sempre menores que os respectivos amostrais. Os valores de máximo e mínimo das co-estimativas revelam ocorrência do efeito de suavização, exceto ao se utilizar cokrigagem colocalizada com Modelo de Markov. As co-estimativas obtidas por esse método correlacionaram-se melhor com as medidas de impedância acústica, mas essa correlação é muito baixa e inferior à obtida a partir dos dados amostrais. Adicionalmente, foi feita a caracterização petrofísica das fácies litológicas descritas para esse campo, elaborado o modelo tridimensional de fácies e calculado o volume poroso do reservatório. A fácies 1 constitui o reservatório de melhor qualidade, pois apresenta maiores valores de porosidade e permeabilidade. A fácies 2 representa um reservatório de qualidade inferior por ser porosa e menos permeável que a primeira. As fácies 3 e 4 são rochas capeadoras devido aos seus baixos valores de porosidade e permeabilidade. No modelo faciológico, as fácies 1, 2 e 4 ocorrem intercaladas, enquanto a fácies 3 apresenta distribuição mais ampla e contínua. Quanto aos volumes porosos, os maiores valores foram obtidos para os reservatórios definidos com base nos modelos de porosidade estimados pela cokrigagem colocalizada com utilização do Modelo de Markov e pela cokrigagem ordinária a partir dos dados heterotópicos. / Data used for studying petroleum reservoirs are obtained through drill core, well logs, seismic records and, as a consequence, they present different sampling scales. Multivariate geostatistics is a manner of integrating these data in order to co-estimate a poorly sampled variable based not only on its own information but also on a densely sampled variable. In this study, ordinary cokriging, collocated cokriging and kriging with external drift were applied to co-estimate porosity in the Namorado Oil Field based on measures of acoustic impedance. Correlation coefficients between co-estimates and sample porosity values, sample statistics and correlation coefficients between co-estimates and acoustic impedance measures have been examined. Correlation between co-estimated and sample values of porosity is about 0.7. Lower correlation was obtained by ordinary cokriging applied to heterotopic data. Co-estimates statistics such as mean, median and standard deviation are always lower than their equivalent sample statistics. Values of maximum and minimum indicate that co-estimates were smoothed except for collocated cokriging with Markov Chain results. Co-estimates obtained by this last method also presented the best correlation to acoustic impedance measures, though this correlation is very low and lower than that calculated through sample data. In addition to that, it was done petrophysical characterization of lithologic facies described for this oil field, elaborated 3D facies model and calculated the porous volume of the reservoir. Facies 1 constitutes a high quality reservoir rock since it presents the highest values of porosity and permeability. Facies 2 represents a inferior quality reservoir rock because it is porous but less permeable than the first. Facies 3 and 4 are seal rock for their low porosity and permeability values. In 3D model, facies 1, 2 and 4 are intercalated to each other while facies 3 presents a wider and more continuous distribution. Finally, the porous volumes were higher for the reservoirs defined based on porosity models estimated by collocated cokriging with Markov Chain and ordinary cokriging applied to heterotopic data.

Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on Dec. 21, 2007). Includes bibliographical references (p. 199-216).

By the evolving application of technology in the oil and gas fields, the volume of gathered information through the dynamic surveillance gets enormous. The importance is lying not only in the regular storage and standalone usage of such a big volume of data but also analyzing and integrating them in the light of alternative sources of data in order to turn the data to valuable field performance information. It is aimed to investigate role of the real time (bottom hole temperature gauges and distributed temperature sensor) and dynamic surveillance (PBU/PFO, production test results etc.) data in effectively managing ACG field. The case study has been carried out by integrating various sources of surveillance data (well test, DTS, PBU) with flowing bottomhole temperature and pressure in order to show the response of production wells to offset producers as wells as water injection and gas injection wells. It has been observed that the reservoir pressure change impacts on the GOR trend which in turn is reflected on the FBHT by means of Joule-Thomson effect. Analyzed Azeri filed examples shows that the change in FBHT is dependant on the rate of change of the reservoir pressure as well as the gas saturation. Also, there are several Azeri field examples that confirm the observed FBHT and FBHP fluctuations is the informer of the instability in the lift performance as a result of GOR decline. Along with above study, investigation of correlation between FBHT and measured GOR from an Azeri production well revealed that there exists a flow regime dependent linear correlation between these parameters. Such a correlation is applied in Azeri wells to predict the &lsquo / real-time&rsquo / GOR in the production wells.

Quick evaluation of reservoir performance is a main concern in decision making. Time-consuming input data preparation and computing, along with data uncertainty tend to inhibit the use of numerical reservoir simulators. New analytical solutions are developed for capacitance-resistive models (CRMs) as fast predictive techniques, and their application in history-matching, optimization, and evaluating reservoir uncertainty for water/CO₂ floods are demonstrated. Because the CRM circumvents reservoir geologic modeling and saturation-matching issues, and only uses injection/production rate and bottomhole pressure data, it lends itself to rapid and frequent reservoir performance evaluation. This study presents analytical solutions for the continuity equation using superposition in time and space for three different reservoir-control volumes: 1) entire field volume, 2) volume drained by each producer, and 3) drainage volume between an injector/producer pair. These analytical solutions allow rapid estimation of the CRM unknown parameters: the interwell connectivity and production response time constant. The calibrated model is then combined with oil fractional-flow models for water/CO₂ floods to match the oil production history. Thereafter, the CRM is used for prediction, optimization, flood performance evaluation, and reservoir uncertainty quantification. Reservoir uncertainty quantification is directly obtained from several equiprobable history-matched solutions (EPHMS) of the CRM. We validated CRM's capabilities with numerical flow-simulation results and tested its applicability in several field case studies involving water/CO₂ floods. Development and application of fast, simple and yet powerful analytic tools, like CRMs that only rely on injection and production data, enable rapid reservoir performance evaluation with an acceptable accuracy. Field engineers can quickly obtain significant insights about flood efficiency by estimating interwell connectivities and use the CRM to manage and optimize real time reservoir performance. Frequent usage of the CRM enables evaluation of numerous sets of the EPHMS and consequently quantification of reservoir uncertainty. The EPHMS sets provide good sampling domains and reasonable guidelines for selecting appropriate input data for full-field numerical modeling by evaluating the range and proper combination of uncertain reservoir parameters. Significant engineering and computing time can be saved by limiting numerical simulation input data to the EPHMS sets obtained from the CRMs. / text