Master of Science / Department of Geology / Abdelmoneam Raef / This study focuses on characterizing subsurface rock formations of the Wellington Field, in Sumner County, Kansas, for both geosequestration of carbon dioxide (CO₂) in the saline Arbuckle formation, and enhanced oil recovery of a depleting Mississippian oil reservoir. Multi-scale data including rock core plug samples, laboratory ultrasonic P-&S-waves, X-ray diffraction, and well log data including sonic and dipole sonic, is integrated in an effort to evaluate existing rock physics models, with the objective of establishing a model that best represents our reservoir and/or saline aquifer rock formations. We estimated compressional and shear wave velocities of rock core plugs for a Mississippian reservoir and Arbuckle saline aquifer, based on first arrival times using a laboratory setup consisting of an Ult 100 Ultrasonic System, a 12-ton hydraulic jack, and a force gauge; the laboratory setup is located in the geophysics lab in Thompson Hall at Kansas State University. The dynamic elastic constants Young’s Modulus, Bulk Modulus, Shear (Rigidity) Modulus and Poisson’s Ratio have been calculated based on the estimated P- and S-wave velocity data. Ultrasonic velocities have been compared to velocities estimated based on sonic and dipole sonic log data from the Wellington 1-32 well. We were unable to create a transformation of compressional wave sonic velocities to shear wave sonic for all wells where compressional wave sonic is available, due to a lack of understandable patterns observed from a relatively limited dataset. Furthermore, saturated elastic moduli and velocities based on sonic and dipole sonic well logs, in addition to dry rock moduli acquired from core plug samples allowed for the testing of various rock physics models. These models predict effects of changing effective (brine + CO₂ +hydrocarbon) fluid composition on seismic properties, and were compared to known values to ensure accuracy, thus revealing implications for feasibility of seismic monitoring in the KGS 1-32 well vicinity.

[pt] O conhecimento do que acontece no reservatório em produção a partir de variações temporais dos atributos sísmicos devido aos processos dinâmicos vem atingindo um valor crescente na indústria do petróleo, especialmente em arenitos. Este processo possui vários desafios, focados em grande parte a desvendar a superposição dos diferentes efeitos provocados pelas mudanças do reservatório nos dados sísmicos. As propriedades sísmicas são afetadas de maneira complexa por vários fatores, sendo a saturação um dos mais importantes, principalmente em rochas porosas como o arenito. Esta propriedade influencia no módulo elástico da rocha e sua resposta sísmica e, ao mesmo tempo, introduz dispersão da velocidade (variação da velocidade com a freqüência). A transição de fluido efetivo (distribuição homogênea e menores velocidades) para fluido com distribuição heterogênea (e maiores velocidades) estabelece um mecanismo de dispersão presente para freqüências sísmicas in situ, especialmente no arenito. O método mais utilizado para aplicar a técnica de substituição de fluidos se baseia na teoria de Gassmann (1951), que considera o meio poroso estático (estado de isostress), onde o fluido não é afetado pela perturbação da onda. No entanto, pesquisas mostram que as velocidades acústicas em rochas saturadas de fluido dependem da freqüência, do tipo de fluido e sua distribuição no meio poroso, viscosidade e outras propriedades que tornam as ondas dispersivas. Neste trabalho são realizadas simulações de fluxo de reservatórios, transformações de física de rochas, upscaling e modelagem sísmica em cenários de injeção de gás com o objetivo de esclarecer a importância de levar em conta a dispersão da velocidade na análise time-lapse. Para isso, são analisados para cada modelo mapas de saturação, velocidade, impedância e sismogramas sintéticos (seções de contraste) calculados com as teorias de substituição Gassmann (1951) e Mavko E Jizba (1991). Os resultados mostram que a resposta sísmica pode ter um incremento de até 15 por cento quando a dispersão devida ao fluxo local é considerada. Porosidade e tortuosidade são parâmetros essenciais que influenciam de maneira diferente na resposta sísmica. / [en] The evaluation of reservoir dynamics during production through time-lapse interpretation has reached a substantial importance in the petroleum industry, mainly in sandstones. This evaluation presents many challenges, mainly concerned to unmask the overlapping of different effects in seismic data due to reservoir changes. Several factors affect seismic properties and saturation is one of the most important. This property influences the rock bulk modulus and seismic response and also causes a velocity dependence on the frequency. This phenomenon is known as velocity dispersion. Furthermore, the transition from effective homogeneous fluid to heterogeneous saturation represents a dispersion mechanism that appears for seismic frequencies in situ in sandstones. The most commonly method used to perform the fluid substitution technique is based in Gassmann theory (1951). This approach considers a static porous media (isostress condition), where fluid is not affected by wave propagation. However, it is well known that acoustic velocities in fluid saturated rocks depends on frequency, according to fluid type and distribution on porous media, viscosity, and others properties that become waves dispersive. In this work reservoir flow-simulation, rock physics transformations, upscaling and seismic modeling were performed in gas injection scenarios. Synthetic seismograms and some contrast sections were generated using Gassmann (1951) and Mavko & Jizba (1991) substitution theories. The goal is to clarify the relevance of considering velocity dispersion on time-lapse seismic analyzing possible differences in the seismic parameters. Results show that seismic response could increase in 15% when squirt flow dispersion is considered. Porosity and tortuosity are essential parameters to analyze seismic response.

Worldwide interest in gas production from shale formations has rapidly increased in recent years, mostly by the successful development of gas shales in North America. The Haynesville Shale is a productive gas shale resource play located in Texas and Louisiana. It produces primarily through enhanced exposure to the reservoir and improved permeability resulting from horizontal drilling and hydraulic fracturing. Accordingly, it is important to estimate the reservoir properties that influence the elastic and geomechanical properties from seismic data. This thesis estimates pore shapes, which affect the transport, elastic, and geomechancial properties, from wellbore seismic velocity in the Haynesville Shale. The approach for this work is to compare computed velocities from an appropriate rock physics model to measured velocities from well log data. In particular, the self-consistent approximation was used to calculate the model-based velocities. The Backus average was used to upscale the high-frequency well log data to the low-frequency seismic scale. Comparisons of calculated velocities from the self-consistent model to upscaled Backus-averaged velocities (at 20 Hz and 50 Hz) with a convergence of 0.5% made it possible to estimate pore aspect ratios as a function of depth. The first of two primary foci of this approach was to estimate pore shapes when a single fluid was emplaced in all the pores. This allowed for understanding pore shapes while minimizing the effects of pore fluids. Secondly, the effects of pore fluid properties were studied by comparing velocities for both patchy and uniform fluid saturation. These correspond to heterogeneous and homogeneous fluid mixing, respectively. Implementation of these fluid mixtures was to model them directly within the self-consistent approximation and by modeling dry-rock velocities, followed by standard Gassmann fluid substitution. P-wave velocities calculated by the self-consistent model for patchy saturation cases had larger values than those from Gassmann fluid substitution, but S-wave velocities were very similar. Pore aspect ratios for variable fluid properties were also calculated by both the self-consistent model and Gassmann fluid substitution. Pore aspect ratios determined for the patchy saturation cases were the smallest, and those for the uniform saturation cases were the largest. Pore aspect ratios calculated by Gassmann fluid substitution were larger because the velocity is inversely related to the aspect ratio in this particular modeling procedure. Estimates of pore aspect ratios for uniform saturation were 0.051 to 0.319 with the average of 0.171 from the velocity modeling using the self-consistent model. For patchy saturation, the aspect ratios were 0.035 to 0.296 with a mean of 0.145. These estimated pore aspect ratios from the patchy saturation case within the self-consistent model are considered the most reasonable set of values I determined. This is because the most likely in-situ fluid distribution is heterogeneous due to the extremely low permeability of the Haynesville Shale. Estimated pore aspect ratios using this modeling help us to understand elastic properties of the Haynesville Shale. In addition, this may help to find zones that correspond to optimal locations for fracturing the shale while considering brittleness and in-situ stress of the formation. / text

Magister Scientiae - MSc / Pressure drop within a field can be attributed to several factors. Pressure drop occurs when fractional forces cause resistance to flowing fluid through a porous medium. In this thesis, the sciences of petrophysics and rock physics were employed to develop understanding of the physical processes that occurs in reservoirs. This study focussed on the physical properties of rock and fluid in order to provide understanding of the system and the mechanism controlling its behaviour. The change in production capacity of wells E-M 1, 2, 3, 4&5 prompted further research to find out why the there will be pressure drop from the suits of wells and which well was contributing to the drop in production pressure. The E-M wells are located in the Bredasdorp Basin and the reservoirs have trapping mechanisms of stratigraphical and structural systems in a moderate to good quality turbidite channel sandstone. The basin is predominantly an elongated north-west and south-east inherited channel from the synrift sub basin and was open to relatively free marine circulation. By the southwest the basin is enclose by southern Outeniqua basin and the Indian oceans. Sedimentation into the Bredasdorp basin thus occurred predominantly down the axis of the basin with main input direction from the west. Five wells were studied E-M1, E-M2, E-M3, E-M4, and E-M5 to identify which well is susceptible to flow within this group. Setting criteria for discriminator the result generated four well as meeting the criteria except for E-M1. The failure of E-M1 reservoir well interval was in consonant with result showed by evaluation from the log, pressure and rock physics analyses for E-M1.iv Various methods in rock physics were used to identify sediments and their conditions and by applying inverse modelling (elastic impedance) the interval properties were better reflected. Also elastic impedance proved to be an economical and quicker method in describing the lithology and depositional environment in the absence of seismic trace.