Made available in DSpace on 2014-06-11T19:26:14Z (GMT). No. of bitstreams: 0 Previous issue date: 2012-04-20Bitstream added on 2014-06-13T18:47:38Z : No. of bitstreams: 1 benvenutti_cf_me_rcla.pdf: 5702564 bytes, checksum: 3468aeafad128f8380c10b5ae674509f (MD5) / A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades... / The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below)

Magister Scientiae - MSc / This research was aimed at employing the broad use of petrophysical analysis and reservoir modelling techniques to explore the petroleum resources in the sandstone units of deep marine play in the Bredasdorp Basin. / South Africa

No description available.

A large percentage of oil and gas reservoirs in the most productive regions such as the Middle East, South America, and Southeast Asia are naturally fractured reservoirs (NFR). The major difference between conventional reservoirs and naturally fractured reservoirs is the discontinuity in media in fractured reservoir due to tectonic activities. These discontinuities cause remarkable difficulties in describing the petrophysical structures and the flow of fluids in the fractured reservoirs. Predicting fluid flow behavior in naturally fractured reservoirs is a challenging area in petroleum engineering. Two classes of models used to describe flow and transport phenomena in fracture reservoirs are discrete and continuum (i.e. dual porosity) models. The discrete model is appealing from a modeling point of view, but the huge computational demand and burden of porting the fractures into the computational grid are its shortcomings. The affect of natural fractures on the permeability anisotropy can be determined by considering distribution and orientation of fractures. Representative fracture permeability, which is a crucial step in the reservoir simulation study, must be calculated based on fracture characteristics. The diagonal representation of permeability, which is customarily used in a dual porosity model, is valid only for the cases where fractures are parallel to one of the principal axes. This assumption cannot adequately describe flow characteristics where there is variation in fracture spacing, length, and orientation. To overcome this shortcoming, the principle of the full permeability tensor in the discrete fracture network can be incorporated into the dual porosity model. Hence, the dual porosity model can retain the real fracture system characteristics. This study was designed to develop a novel approach to integrate dual porosity model and full permeability tensor representation in fractures. A fully implicit, parallel, compositional chemical dual porosity simulator for modeling naturally fractured reservoirs has been developed. The model is capable of simulating large-scale chemical flooding processes. Accurate representation of the fluid exchange between the matrix and fracture and precise representation of the fracture system as an equivalent porous media are the key parameters in utilizing of dual porosity models. The matrix blocks are discretized into both rectangular rings and vertical layers to offer a better resolution of transient flow. The developed model was successfully verified against a chemical flooding simulator called UTCHEM. Results show excellent agreements for a variety of flooding processes. The developed dual porosity model has further been improved by implementing a full permeability tensor representation of fractures. The full permeability feature in the fracture system of a dual porosity model adequately captures the system directionality and heterogeneity. At the same time, the powerful dual porosity concept is inherited. The implementation has been verified by studying water and chemical flooding in cylindrical and spherical reservoirs. It has also been verified against ECLIPSE and FracMan commercial simulators. This study leads to a conclusion that the full permeability tensor representation is essential to accurately simulate fluid flow in heterogeneous and anisotropic fracture systems. / text

<p>This research was aimed at employing the broad use of petrophysical analysis and reservoir modelling techniques to explore the petroleum resources in the sandstone units of deep marine play in the Bredasdorp Basin.</p>

Hydrocarbon reserves are generally produced through wells drilled into reservoir pay zones. During production, gas liberation from the oil phase occurs due to pressure decline in the wellbore. Thus, we expect multiphase flow in some sections of the wellbore. As a multi-phase/multi-component gas-oil mixture flows from the reservoir to the surface, pressure, temperature, composition, and liquid holdup distributions are interrelated. Modeling these multiphase flow parameters is important to design production strategies such as artificial lift procedures. A wellbore fluid flow model can also be used for pressure transient test analysis and interpretation. Considering heat exchange in the wellbore is important to compute fluid flow parameters accurately. Modeling multiphase fluid flow in the wellbore becomes more complicated due to heat transfer between the wellbore fluids and the surrounding formations. Due to mass, momentum, and energy exchange between the wellbore and the reservoir, the wellbore model should be coupled with a numerical reservoir model to simulate fluid flow accurately. This model should be non-isothermal to consider the effect of temperature. Our research shows that, in some cases, ignoring compositional effects may lead to errors in pressure profile prediction for the wellbore. Nearly all multiphase wellbore simulations are currently performed using the "black oil" approach. The primary objective of this study was to develop a non-isothermal wellbore simulator to model transient fluid flow and temperature and couple the model to a reservoir simulator called General Purpose Adaptive Simulator (GPAS). The coupled wellbore/reservoir simulator can be applied to steady state problems, such as production from, or injection to a reservoir as well as during transient phenomena such as well tests to accurately model wellbore effects. Fluid flow in the wellbore may be modeled either using the blackoil approach or the compositional approach, as required by the complexity of the fluids. The simulation results of the new model were compared with field data for pressure gradients and temperature distribution obtained from wireline conveyed pressure recorder and acoustic fluid level measurements for a gas/oil producer well during a buildup test. The model results are in good agreement with the field data. Our simulator gave us further insights into the wellbore dynamics that occur during transient problems such as phase segregation and counter-current multiphase flow. We show that neglecting these multiphase flow dynamics would lead to unreliable results in well testing analysis.

A significant percentage of computational time in compositional simulations is spent performing flash calculations to determine the equilibrium compositions of hydrocarbon phases in situ. Flash calculations must be done at each time step for each grid block; thus billions of such calculations are possible. It would be very important to reduce the computational time of flash calculations significantly so that more grid blocks or components may be used. In this dissertation, three different methods are developed that yield fast, robust and accurate phase behavior calculations useful for compositional simulation and other applications. The first approach is to express the mixing rule in equations-of-state (EOS) so that a flash calculation is at most a function of six variables, often referred to as reduced parameters, regardless of the number of pseudocomponents. This is done without sacrificing accuracy and with improved robustness compared with the conventional method. This approach is extended for flash calculations with three or more phases. The reduced method is also derived for use in stability analysis, yielding significant speedup. The second approach improves flash calculations when K-values are assumed constant. We developed a new continuous objective function with improved linearity and specified a small window in which the equilibrium compositions must lie. The calculation speed and robustness of the constant K-value flash are significantly improved. This new approach replaces the Rachford-Rice procedure that is embedded in the conventional flash calculations. In the last approach, a limited compositional model for ternary systems is developed using a novel transformation method. In this method, all tie lines in ternary systems are first transformed to a new compositional space where all tie lines are made parallel. The binodal curves in the transformed space are regressed with any accurate function. Equilibrium phase behavior calculations are then done in this transformed space non-iteratively. The compositions in the transformed space are translated back to the actual compositional space. The new method is very fast and robust because no iteration is required and thus always converges even at the critical point because it is a direct method. The implementation of some of these approaches into compositional simulators, for example UTCOMP or GPAS, shows that they are faster than conventional flash calculations, without sacrificing simulation accuracy. For example, the implementation of the transformation method into UTCOMP shows that the new method is more than ten times faster than conventional flash calculations.

Many hydrocarbon reservoirs have sufficient porosity but low permeability (for example, tight gas sands and coal beds). However, such reservoirs are often naturally fractured. The fracture patterns in these reservoirs can control flow and transport properties, and therefore, play an important role in drilling production wells. On the scale of seismic wavelengths, closely spaced parallel fractures behave like an anisotropic media, which precludes the response of individual fractures in the seismic data. There are a number of fracture parameters which are needed to fully characterize a fractured reservoir. However, seismic data may reveal only certain fracture parameters and those are fracture orientation, crack density and fracture infill. Most of the widely used fracture characterization methods such as Swave splitting analysis or amplitude vs. offset and azimuth (AVOA) analysis fail to render desired results in laterally varying media. I have conducted a systematic study of the response of fractured reservoirs with laterally varying elastic and fracture properties, and I have developed a scheme to invert for the fracture parameters. I have implemented a 3D finite-difference method to generate multicomponent synthetic seismic data in general anisotropic media. I applied the finite-difference algorithm in both Standard and Rotated Staggered grids. Standard Staggered grid is used for media having symmetry up to orthorhombic (isotropic, transversely isotropic, and orthorhombic), whereas Rotated Staggered grid is implemented for monoclinic and triclinic media. I have also developed an efficient and accurate ray-bending algorithm to compute seismic traveltimes in 3D anisotropic media. AVOA analysis is equivalent to the first-order Born approximation. However, AVOA analysis can be applied only in a laterally uniform medium, whereas the Born-approximation does not pose any restriction on the subsurface structure. I have developed an inversion scheme based on a ray-Born approximation to invert for the fracture parameters. Best results are achieved when both vertical and horizontal components of the seismic data are inverted simultaneously. I have also developed an efficient positivity constraint which forbids the inverted fracture parameters to be negative in value. I have implemented the inversion scheme in the frequency domain and I show, using various numerical examples, that all frequency samples up to the Nyquist are not required to achieve desired inversion results.

<p>This research was aimed at employing the broad use of petrophysical analysis and reservoir modelling techniques to explore the petroleum resources in the sandstone units of deep marine play in the Bredasdorp Basin.</p>

[Truncated abstract] This thesis describes the development of synthetic rock samples, representative of core samples from hydrocarbon reservoirs. The basic process consists of screening and sorting silica particles into discrete grain sizes, and then binding them together using a proprietary process known as CIPS, (Calcite In-situ Precipitation System). In the bonding process, the porosity of the system is substantially preserved, and the technique allows the manufacture of synthetic core samples with a tailor-made permeability. The produced samples were extensively characterised using a variety of analytic techniques to determine their porosity, permeability and pore size distribution. These analyses were a necessary pre-cursor to a major part of this thesis: the characterisation of the pore space by nuclear magnetic resonance (NMR) techniques. The synthetic core samples, covering a 7 times factor in grain sizes were examined using NMR, and this data formed the comparative basis for the NMR studies that followed. Two fundamental NMR questions were posed and answered in this thesis: 1. What is the effect of paramagnetic ions in the rock matrix on the NMR response? In pursuit of this question the CIPS process was extended to include co-precipitation of paramagnetic ions. A key feature is that the ions were deposited in predictable amounts at known sites (on the wall of the pore space). ... The NMR response in these double cores was then measured and examined to provide an answer to the question posed at the beginning of this paragraph. The significance of this work is that the physically distinct cores are a cylindrical analogue of adjoining sedimentary strata. By answering the question posed above, the thesis gives an indication of the vertical porosity resolution ultimately possible in an NMR logging tool. At present this ranges from 9” to 24” in the most favourable circumstances. This work suggests that the NMR signal carries porosity information at a much higher resolution, and that advanced numerical analysis of the NMR signature could realise the potential of greater stratigraphic resolution in NMR logging In addition to the research outlined above, the application of the CIPS technique to produce analogues of reservoir rocks, pioneered in this thesis, has stimulated similar research to be undertaken at other institutions, including the fabrication of synthetic reservoir cores containing clay particles (at CSIRO - the Commonwealth Scientific and Industrial Research Organisation) and a large scale application, formation of meter size blocks of CIPS bonded material, with separate strata, for laboratory studies of seismic waves (at Curtin University)