Stable dispersions of magnetic nanoparticles that are already in use in biomedicine as image-enhancing agents, also have potential use in subsurface applications. Surface-coated nanoparticles are capable of flowing through micron-size pores across long distances in a reservoir with modest retention in rock. Tracing these contrast agents using the current electromagnetic tomography technology could potentially help track the flood-front in waterflood and EOR processes and characterize the reservoir. The electromagnetic (EM) tomography used in the petroleum industry today is based on the difference between the electrical conductivity of reservoir fluids as well as other subsurface entities. The magnetic nanoparticles that are considered in this study, however, change the magnetic permeability of the flooded region, which is a novel application of the existing EM tomography technology. As the first fundamental step, the magnetic permeability change in rock due to injecting magnetic nanoparticles is quantified as a function of particle and reservoir properties. Subsequently, a new formulation is devised to compute the sensitivity of magnetic measurements to magnetic permeability perturbations. The results are then compared with the sensitivity to conductivity perturbations to identify the application space of magnetic contrast agents. Using numerical simulations, the progress of magnetic nanoparticle bank is monitored in the reservoir through time-lapse magnetic tomography measurements that are expected. Initially, simple models for displacement of injection banks are assumed and the level of complexity is gradually increased to incorporate the realities of fluid flow in the reservoir. The fluid-flow behavior of the nanoparticles is dynamically integrated with time-lapse magnetic response. Since the nanoparticles could help illuminate the flow paths, they could be used to indirectly measure reservoir heterogeneities. Therefore, numerous case studies are demonstrated where reservoir heterogeneity could potentially be inferred. Finally, fundamental pore-scale models are developed as a first step towards the multiple fluid phases extension of the EM tomography application. Using magnetic nanoparticles to improve electromagnetic tomography provides several strategic advantages. One key advantage is that the magnetic nanoparticles provide high resolution measurements at very low frequencies where the conductivity contrast is hardly detectable and casing effect is manageable. In addition, the sensitivity of magnetic measurements at the early stages of the flood is significantly improved with magnetic nanoparticles. Moreover, the vertical resolution of magnetic measurements is significantly enhanced with magnetic nanoparticles present in the vicinity of source or receiver. The fact that the progress of the magnetic slug can be detected at very early stages of the flood, that the traveling slug’s vertical boundaries can be identified at low frequencies, that the reservoir heterogeneities could potentially be characterized, and that the magnetic nanoparticles can be sensed much before the actual arrival of the slug at the observer well, provides significant value of using magnetic contrast agents for reservoir illumination. / text

The performance of Enhanced Oil Recovery (EOR) processes is adversely affected by the heterogeneous distribution of flow properties of the rock. The effects of heterogeneity are further highlighted when the mobility ratio between the displacing and the displaced fluids is unfavorable. Polymer flooding aims to mitigate this by controlling the mobility ratio resulting in an increase in the volumetric swept efficiency. However, the design of the polymer injection process has to take into account the uncertainty due to a limited knowledge of the heterogeneous properties of the reservoir. Numerical reservoir models equipped with the most updated, yet uncertain information about the reservoir should be employed to optimize the operational settings. Consequently, the optimal settings are uncertain and should be revised as the model is updated. In this report, a feedback-control scheme is proposed with a model updating step that conditions prior reservoir models to newly obtained dynamic data, and this followed by an optimization step that adjusts well control settings to maximize (or minimize) an objective function. An illustration of the implementation of the proposed closed-loop scheme is presented through an example where the rate settings of a well affected by water coning are adjusted as the reservoir models are updated. The revised control settings yield an increase in the final value of the objective function. Finally, a fast analog of a polymer flooding displacement that traces the movement of random particles from injectors to producers following probability rules that reflect the physics of the actual displacement is presented. The algorithm was calibrated against the full-physics simulation results from UTCHEM, the compositional chemical flow simulator developed at The University of Texas at Austin. This algorithm can be used for a rapid estimation of basic responses such as breakthrough time or recovery factor and to provide a simplified characterization the reservoir heterogeneity. This report is presented to fulfill the requirements to obtain the degree of Master of Science in Engineering under fast track option. It summarizes the research proposal presented for my doctorate studies that are currently ongoing. / text

The Late Jurassic Arab D Formation in Saudi Arabia hosts the some of the world’s largest hydrocarbon reservoirs including Ghawar, the world’s largest oil field, and Khurais, the world’s largest supergiant to come into production in the last 5 years. Despite the vast oil reserves within the Arab D, and the central role of this reservoir at Ghawar in making up short-falls in global production, our understanding of the much fundamental characterization work both in terms of modern sequence stratigraphic reservoir frameworks and linked structural/fracture characterization. This study of Arab D reservoir at Qatif, immediately to the north of Ghawar, provides one of the first looks at a modern sequence analysis of this producing interval and illustrates that porosity zonations, and ultimately flow unit architecture may be substantially different than currently in use. The Arab D of the Arabian Plate is a carbonate ramp system of exceedingly low angle (<1o) developed during a low-eustatic-amplitude greenhouse Milankovitch setting. Combined macroscopic and petrographic data analysis allowed recognition of nine depositional facies: 1) spiculitic wackestone, 2) Planolites-burrowed wackestone, 3) bioturbated skeletal-peloidal packstone, 4) pelletal packstone, 5) peloidal-skeletal grain dominated packstone, 6) peloidal-skeletal grainstone, 7) skeletal-ooids grainstone, 8) cryptalgal laminites and 9) anhydrite. The depositional facies defined are used to interpret three facies tracts from deep to shallow across the ramp profile: 1) low energy sub-storm wave base (SWB) dominated facies that may illustrate disaerobic tendencies, 2) high energy within-fair-weather-wave-base ramp-crest or mid-ramp facies including foreshore and upper shoreface oolitic and skeletal grainstones that define one of the key reservoir pay zones and 3) back-barrier tidal flats consisting of cryptalgal laminites, sabkha-type anhydrites, and salina-type anhydrites. Three high frequency sequences are defined: QSEQ 1 is asymmetrical, dominated by subtidal lithofacies; and QSEQ 2 and QSEQ 3 are symmetrical and record a complex history of the fill on an intrashelf basin. Detailed cycle-scale correlations using core-based cycles and wireline log patterns allowed a cycle-scale correlation framework to be established that illustrates a north to south progradation of the Arab D reservoir strata, building landward from the Rimthan Arch. Diagenetic features observed in the Arab D reservoir include fitted fabric (chemical compaction), dolomitization, and cementation. These features play a major role altering reservoir quality properties as they essentially control fluid flow pathways which ultimately alter primary porosity and permeability. / text

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Characterization of carbonate reservoirs by flow units is a practical way of reservoir zonation. This study represents a petrophysical-based method that uses well loggings and core plug data to delineate flow units within the most productive carbonate reservoir of Derdere Formation in Y field, Southeast Turkey. Derdere Formation is composed of limestones and dolomites. Logs from the 5 wells are the starting point for the reservoir characterization. The general geologic framework obtained from the logs point out for discriminations within the formation. 58 representative core plug data from 4 different wells are utilized to better understand the petrophysical framework of the formation. The plots correlating petrophysical parameters and the frequency histograms suggest the presence of distinctive reservoir trends. These discriminations are also represented in Winland porosity-permeability crossplots resulted in clusters for different port-sizes that are responsible for different flow characteristics. Although the correlation between core plug porosity and air permeability yields a good correlation coefficient, the formation has to be studied within units due to differences in port-sizes and reservoir process speed. Linear regression and multiple regression analyses are used for the study of each unit. The results are performed using STATGRAPH Version Plus 5.1 statistical software. The permeability models are constructed and their reliabilities are compared by the regression coefficients for predictions in un-cored sections. As a result of this study, 4 different units are determined in the Derdere Formation by using well logging data, and core plug analyses with the help of geostatistical methods. The predicted permeabilities for each unit show good correlations with the calculated ones from core plugs. Highly reliable future estimations can be based on the derived methods.

Reservoir characterization is one of the most important problems in petroleum engineering. It involves forward reservoir modeling that predicts the fluid behavior in the reservoir and inverse problem that calibrates created reservoir models with given data. In this dissertation, we focus on two problems in the field of reservoir characterization: depth of investigation in heterogeneous reservoirs, and history matching and uncertainty quantification of channelized reservoirs. The concept of depth of investigation is fundamental to well test analysis. Much of the current well test analysis relies on analytical solutions based on homogeneous or layered reservoirs. However, such analytic solutions are severely limited for heterogeneous and fractured reservoirs, particularly for unconventional reservoirs with multistage hydraulic fractures. We first generalize the concept to heterogeneous reservoirs and provide an efficient tool to calculate drainage volume using fast marching methods and estimate pressure depletion based on geometric pressure approximation. The applicability of proposed method is illustrated using two applications in unconventional reservoirs including flow regime visualization and stimulated reservoir volume estimation. Due to high permeability contrast and non-Gaussianity of channelized permeability field, it is difficult to history match and quantify uncertainty of channelized reservoirs using traditional approaches. We treat facies boundaries as level set functions and solve the moving boundary problem (history matching) with the level set equation. In addition to level set methods, we also exploit the problem using pixel based approach. The reversible jump Markov Chain Monte Carlo approach is utilized to search the parameter space with flexible dimensions. Both proposed approaches are demonstrated with two and three dimensional examples.

Magister Scientiae - MSc (Earth Science) / The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.

Master of Science / Department of Geology / Abdelmoneam Raef / Seismic reservoir characterization and prospect evaluation based 3D seismic attributes analysis in Kansas has been successful in contributing to the tasks of building static and dynamic reservoir models and in identifying commercial hydrocarbon prospects. In some areas, reservoir heterogeneities introduce challenges, resulting in some wells with poor economics. Analysis of seismic attributes gives insight into hydrocarbon presence, fluid movement (in time lapse mode), porosity, and other factors used in evaluating reservoir potential. This study evaluates a producing lease using seismic attributes analysis of an area covered by a 2010 3D seismic survey in the Morrison Northeast field and Morrison field of Clark County, KS. The target horizon is the Viola Limestone, which continues to produce from seven of twelve wells completed within the survey area. In order to understand reservoir heterogeneities, hydrocarbon entrapment settings and the implications for future development plans, a seismic attributes extraction and analysis, guided with geophysical well-logs, was conducted with emphasis on instantaneous attributes and amplitude anomalies. Investigations into tuning effects were conducted in light of amplitude anomalies to gain insight into what seismic results led to the completion of the twelve wells in the area drilled based on the seismic survey results. Further analysis was conducted to determine if the unsuccessful wells completed could have been avoided. Finally the study attempts to present a set of 3D seismic attributes associated with the successful wells, which will assist in placing new wells in other locations within the two fields, as well as promote a consistent understanding of entrapment controls in this field.

Submitted by RICARDO OTTO ROZZA SCHMIDT null (rottoschmidt@gmail.com) on 2016-06-20T16:57:36Z No. of bitstreams: 1 Mestrado Dissertação Final_Dig.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) / Approved for entry into archive by Ana Paula Grisoto (grisotoana@reitoria.unesp.br) on 2016-06-23T14:12:58Z (GMT) No. of bitstreams: 1 schmidt_ror_me_rcla.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) / Made available in DSpace on 2016-06-23T14:12:58Z (GMT). No. of bitstreams: 1 schmidt_ror_me_rcla.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) Previous issue date: 2016-05-03 / Os arenitos de água profunda, designados genericamente como turbiditos, têm enorme relevância energética e econômica para o Brasil. Na Bacia de Campos, a maior parte dos campos produtores contêm níveis turbidíticos da Formação Carapebus (Eoceno), focalizados neste estudo. É o caso dos campos de Enchova e Bonito. Nesta dissertação propõe-se a caracterização geológica-petrofísica dos reservatórios turbidíticos (Eoceno) nestes campos, que mesmo descobertos há 30 anos detém poucas informações publicadas no que se refere à sua disposição espacial litológica e petrofísica. A integração de metodologias e ferramentas possibilita a melhor compreensão dos reservatórios e de suas heterogeneidades. Neste trabalho foram integrados dados oriundos de testemunhos, perfis de poços, sísmica 3-D (40 km²) por meio dos métodos geoestatísticos Krigagem Indicativa e Krigagem Ordinária, de forma a contribuir com o entendimento da distribuição das principais unidades do reservatório. A análise litológica teve como enfoque os métodos qualitativos, apoiada na descrição de testemunhos apresentadas na pasta de poço, e quantitativo, baseado nas análises dos perfis geofísicos de 20 poços. Com base nesta correlação rocha-perfil, os litotipos arenito, carbonato e folhelho foram definidos e extrapolados para os intervalos não testemunhados. A interpretação e correlação dos perfis geofísicos identificaram dois níveis arenosos principais, o inferior com 10 a 15 m e superior com 70 a100 m, separados por uma camada de folhelho de 5 a 20 m. Salienta-se o controle deposicional de uma feição erosiva de idade Maastrichiano-Eoceno Médio, a qual concentra as maiores espessuras de areia a oeste dos campos. A caracterização estrutural do reservatório, definida por três feições dômicas alinhadas a NE, foi definida pela interpretação sísmica 3-D. A análise de atributos sísmicos de amplitude, realizada no intervalo definido entre os horizontes topo e base do reservatório, revelou geometrias associadas a complexos de canais discretos, em Enchova, e lobos canalizados, em Bonito. O modelo litológico do reservatório obtido pela aplicação da Krigagem indicativa representou satisfatoriamente os níveis turbidíticos quando comparados aos dados de poços e mapas atributos sísmicos, que indica as maiores espessuras dos turbiditos a oeste das áreas. O modelo da porosidade obtido pela Krigagem Ordinária (Krigagem Indicativa) indicou melhores condições porosas na porção oeste dos campos, correlacionando-se com o modelo litológico carbonatos fechados e folhelhos no modelo litológico. Ambos, os mapas de atributos sísmicos e modelos obtidos apresentam uma área com potencial exploratório a sul de Bonito, ainda não perfurada segundo a ANP. / Deep-water sandstones, known as turbidites, play an important role in Brazil's energy and economic scenario. In the Campos Basin, Carapebus Formation´s Eocene turbidites produce in most oil fields of the basin. Enchova and Bonito oil fields, focused in this study, represent Eocene sandstone production areas. Discovered 30 years ago, Eocene reservoirs have a lack of information regarding its lithological and petrophysical distribution. This master thesis proposes a geological-getrophysical reservoir characterization of Eocene turbidites on Enchova and Bonito fields. The integration of methodologies and tools enables a better understanding of the reservoir geometry and heterogeneity. This work integrates core descriptions from well reports, well logs and 3-D seismic through Indicator Kriging (lithology) and Ordinary Kriging (porosity) resulting in 3-D solid models. The models possibly a better understand of lithologic and petrophysical reservoir distribution. The lithological analysis is supported by qualitative methods, supported by the 70m core description provided with well log data, and quantitative, based on the analysis of 20 well logs. Based on this correlation between logs and rocks, the lithology classes, sandstone, carbonate and shale, were defined. The well-logs interpretation and correlation identified two main turbidite intervals, the lower 5 to 15 m and upper 70 to 100 m, separated by a shale layer 5 to 20 m. These intervals were depositionally controlled by an erosive feature associated with Maastrichtian-Middle Eocene unconformity, defining the distribution pattern of turbidites sands concentrated on the western portion of the fields. The reservoir structural characterization, performed trough 3-D seismic interpretation, is defined by three domal features separated by normal faults aligned to NE-SW. Seismic amplitude attributes calculated under the reservoir interval revealed channelized geometries on Enchova field and lobate architecture on Bonito field. The reservoir lithological model obtained through Indicator Kriging demonstrate coherence when compared to well data distribution and seismic attributes maps that indicate turbidite greatest thicknesses in western areas. The model of porosity obtained by Ordinary Kriging revealed best porosity conditions in the western portion of the fields, corresponding to the seismic attributes responses and lithological model. Both geostatistical models and seismic attributes maps revealed an interesting non drilled area located on south of Bonito field.