Multi-scale uncertainty quantification in geostatistical seismic inversion

Geostatistical seismic inversion is commonly used to infer the spatial distribution of the subsurface petro-elastic properties by perturbing the model parameter space through iterative stochastic sequential simulations/co-simulations. The spatial uncertainty of the inferred petro-elastic properties is represented with the updated a posteriori variance from an ensemble of the simulated realizations. Within this setting, the large-scale geological (metaparameters) used to generate the petro-elastic realizations, such as the spatial correlation model and the global a priori distribution of the properties of interest, are assumed to be known and stationary for the entire inversion domain. This assumption leads to underestimation of the uncertainty associated with the inverted models. We propose a practical framework to quantify uncertainty of the large-scale geological parameters in seismic inversion. The framework couples geostatistical seismic inversion with a stochastic adaptive sampling and Bayesian inference of the metaparameters to provide a more accurate and realistic prediction of uncertainty not restricted by heavy assumptions on large-scale geological parameters. The proposed framework is illustrated with both synthetic and real case studies. The results show the ability retrieve more reliable acoustic impedance models with a more adequate uncertainty spread when compared with conventional geostatistical seismic inversion techniques. The proposed approach separately account for geological uncertainty at large-scale (metaparameters) and local scale (trace-by-trace inversion)

Integração da impedância sísmica 3D e 4D ao modelo de simulação para melhorar a caracterização do reservatório

Orientadores: Denis José Schiozer, Alessandra Davólio GomesTese (doutorado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de GeociênciasResumo: O objetivo principal da simulação numérica de reservatórios é prever a produção e planejar o desenvolvimento de campos de petróleo, mantendo modelos de reservatórios confiáveis que respeitem os dados estáticos e dinâmicos disponíveis. A sísmica 4D (S4D) desempenha papel importante no monitoramento de reservatórios, fornecendo dados que descrevem o comportamento dinâmico das propriedades do reservatório durante a produção. Aplicações recentes mostraram que a S4D possibilita reduzir a incerteza na distribuição de heterogeneidades, melhorando o conhecimento da estrutura geológica e permitindo que o reservatório seja gerenciado de forma mais eficaz. Dados de S4D podem ser integrados com dados de simulação do fluxo do reservatório, qualitativamente (como na interpretação de causas prováveis de anomalias devido a mudanças na saturação e pressão dos poros) ou quantitativamente (adicionando atributos derivados da sísmica dentro da função objetivo de um processo de ajuste de histórico). Dados sísmicos 3D são associados aos parâmetros estáticos do reservatório e podem fornecer conhecimento da estrutura e litologia do reservatório. Assim, a integração entre o modelo de simulação de fluxo e os dados sísmicos observados (domínios de engenharia e sísmica) deve respeitar a interpretação dinâmica, estrutural e estratigráfica do reservatório através da modelagem direta e inversa e subsequente comparação entre as observações previstas e reais. Este trabalho destina-se a desenvolver metodologias para usar dados sísmicos 3D e 4D, para mitigar as incertezas no modelo de simulação numérica de reservatórios. Deste modo, este trabalho propõe uma metodologia de estudos para integrar impedância sísmica invertida (3D e 4D) com dados de engenharia, dando ênfase na interface entre modelos estáticos e dinâmicos, para proporcionar um modelo de reservatório mais confiável. A metodologia é aplicada a um reservatório de arenito com geologia estrutural complexa, o benchmark do campo de Norne (Noruega). A primeira parte do trabalho apresenta uma inversão do levantamento sísmico 3D base (adquirido em 2001) discutindo o uso de diferentes números e localização de poços para determinar as características estáticas do reservatório. Demonstrou-se que a inversão 3D fornece melhores resultados se os dados de entrada, neste caso os dados de poço, respeitarem a complexa geologia estrutural do reservatório de Norne. Destacamos as vantagens da interpretação sísmica 4D em forma de impedância, obtida através de inversão sísmica 4D,através da comparação das anomalias de impedância sísmica com as diferenças de amplitude sísmica para alguns exemplos no campo de Norne. A inversão 4D atenua as anomalias que não são causadas pelas atividades produtivas do campo. Em seguida, interpretamos as variações de impedância entre os levantamentos sísmicos base (2001) e monitor (2006) para todo o campo para identificar anomalias de impedância 4D (sinais de aumento e diminuição de impedância) e desacoplar os efeitos das variações de fluido e pressão (devido à atividade de produção) suportado por dados de engenharia do reservatório. Assim, uma interpretação sísmica 4D qualitativa precisa foi alcançada através dos resultados da inversão permitindo entender os efeitos da atividade de produção, que é outra contribuição importante a ser destacada. A natureza multidisciplinar da modelagem do reservatório exige uma abordagem mais quantitativa para integrar os dados sísmicos 4D na metodologia de ajuste de histórico. A avaliação quantitativa da consistência entre a simulação do fluxo do reservatório e os parâmetros elásticos necessita de um modelo petro-elástico (PEM) para fornecer uma comparação lógica entre domínios. No entanto, o PEM pode ser bastante incerto. Assim, atualizamos o modelo do reservatório usando a integração quantitativa da impedância sísmica invertida (3D e 4D) dentro do modelo de simulação de fluxo do reservatório, levando em consideração que o desajuste de dados sísmicos pode ser associado à um modelo de simulação incerto, ou à um PEM incerto. O caso estudado mostrou um desajuste considerável entre dados simulados e observados de pressão de fundo dos poços. Portanto, propomos duas etapas para resolver a ambiguidade na geração de um modelo de simulação de reservatório confiável tendo um PEM incerto. Em primeiro lugar, melhoramos a confiabilidade do modelo de reservatório usando a integração quantitativa da impedância sísmica observada em 3D e 4D, juntamente com os dados do histórico dos poços. Em seguida, calibramos os parâmetros no modelo petro-elástico, referente aos dados observados 4D e ao histórico de produção para garantir valores realistas às mudanças nos parâmetros elásticos in situ devido à atividade de produção. Este estudo apresenta a integração dos domínios de engenharia e sísmica, em um fluxo de trabalho iterativo, em um campo real para fechar o ciclo entre os dois domínios, permitindo atualizar o modelo de reservatório e validar o modelo petro-elástico. A principal contribuição deste trabalho é destacar a incorporação dos dados estáticos e dinâmicos do reservatório para diagnosticar a confiabilidade da simulação de fluxo do reservatório para um caso complexo, considerando as incertezas inerentes a esses dados e melhorando a compreensão do comportamento do reservatórioAbstract: The ultimate goal of reservoir simulation in reservoir surveillance technology is to estimate long-term production forecasting and to plan further development of petroleum fields by maintaining reliable reservoir models that honor available static and dynamic data. Moreover, time-lapse seismic (or 4DS) has played a preeminent role in the reservoir surveillance technology by providing new data describing the dynamic behavior of reservoir properties during production. Recent applications have shown that 4DS yields a reduction in the uncertainty in reservoir properties allowing the improvement of the knowledge of the geological framework and a more effective reservoir management. 4DS response can be integrated with reservoir flow simulation either qualitatively (such as interpreting likely causes of 4D anomalies due to changes in saturation and pore pressure) or quantitatively (by adding seismic derived attributes inside the objective function of a history matching process). Alternatively, 3D seismic data is associated to the static reservoir parameters which can provide reservoir framework knowledge. Thus, closing the loop between the flow simulation model and the observed seismic data (engineering and seismic domains) must honor static, dynamic, structural and stratigraphic interpretation of reservoirs through forward and inverse modeling and consequent comparison between predicted and actual observations. This work aims using 3D and 4D seismic data to mitigate uncertainties in numerical reservoir simulation model, proposing a circular workflow of inverted seismic impedance (3D and 4D) and engineering studies, with emphasis on the interface between static and dynamic models. The methodology is applied to a complex structural geology, sandstone reservoir, the Norne Field benchmark case (Norway). The first part of the work presents a 3D seismic inversion of the baseline seismic survey (2001) discussing different numbers and locations of wells to characterize the static reservoir framework. It was shown that the 3D inversion provides better results if the input data, in this case the well-logs data, respect the complex structural geology of Norne reservoir. Meanwhile, we highlight the advantages of time-lapse seismic interpretation in form of inverted impedance by running 4D seismic inversion and comparing derived seismic impedance anomalies within the standard seismic amplitude differences for some examples in the Norne Field. The 4D inversion mitigates the anomalies that are not caused by production activity. Then, we interpret impedance variations between the base (2001) and monitor (2006) seismic surveys for entire field to identify 4D impedance anomalies (hardening and softening signals) and decouple the effects of fluid and pressure variations (due to the production activity), supported by reservoir engineering data. Thus, an accurate qualitative 4D seismic interpretation are provided by inversion results to be able to understand the effects of production activity, which is another important contribution to be highlighted. However, the multidisciplinary nature of reservoir modeling demands more quantitative approach to integrate 4D seismic data into the history matching workflows. Nevertheless, quantitative evaluation of consistency between reservoir flow simulation and elastic parameters relies on calibrated petro-elastic modelling (PEM) to provide the logical cross-domain comparison. However the petro-elastic model can be very uncertain. Thereby, we update the reservoir model using quantitative integration of seismic inverted impedance (3D and 4D) within reservoir flow simulation model, taking into account that the seismic data mismatch can be associated to an uncertain simulation model as well as to an uncertain PEM. The case studied presented a considerable initial mismatch between simulated and measured bottom-hole pressure (BHP). We therefore propose two steps in order to resolve ambiguity in generating validated reservoir flow simulation and PEM model. First, we improve the reliability of reservoir model using quantitative integration of 3D and 4D observed seismic impedance together with well history data. Eventually, we calibrate the parameters in petro-elastic model, referring to 4D observed and production history data to ensure realistic values for changes in in-situ elastic parameters due to the production activity. This study presents the integration of engineering and seismic domains, in an iterative workflow, on a real field to close the loop and subsequently to update reservoir flow simulation and validate the petro-elastic model. The main contributions of this work is to highlight the incorporation of available static and dynamic reservoir data to diagnose the reservoir flow simulation reliability for a complex case, considering the uncertainties inherent to these data and improve the reservoir behavior understandingDoutoradoReservatórios e GestãoDoutor em Ciências e Engenharia de Petróle

Controlling realism and uncertainty in reservoir models using intelligent sedimentological prior information

Forecasting reservoir production has a large associated uncertainty, since this is the final part of a very complex process, this process is based on sparse and indirect data measurements. One the methodologies used in the oil industry to predict reservoir production is based on the Baye’s theorem. Baye’s theorem applied to reservoir forecasting, samples parameters from a prior understanding of the uncertainty to generate reservoir models and updates this prior information by comparing reservoir production data with model production response. In automatic history matching it is challenging to generate reservoir models that preserve geological realism (obtain reservoir models with geological features that have been seen in nature). One way to control the geological realism in reservoir models is by controlling the realism of the geological prior information. The aim of this thesis is to encapsulate sedimentological information in order to build prior information that can control the geological realism of the history-matched models. This “intelligent” prior information is introduced into the automatic history-matching framework rejecting geologically unrealistic reservoir models. Machine Learning Techniques (MLT) were used to build realistic sedimentological prior information models. Another goal of this thesis was to include geological parameters into the automatic history-match framework that have an impact on reservoir model performance: vertical variation of facies proportions, connectivity of geobodies, and the use of multiple training images as a source of realistic sedimentological prior information. The main outcome of this thesis is that the use of “intelligent” sedimentological prior information guarantees the realism of reservoir models and reduces computing time and uncertainty in reservoir production prediction

Investigation of pressure and saturation effects on elastic parameters: an integrated approach to improve time-lapse interpretation

Time-lapse seismic is a modern technology for monitoring production-induced changes in and around a hydrocarbon reservoir. Time-lapse (4D) seismic may help locate undrained areas, monitor pore fluid changes and identify reservoir compartmentalization. Despite several successful 4D projects, there are still many challenges related to time-lapse technology. Perhaps the most important are to perform quantitative time-lapse and to model and interpret time-lapse effects in thin layers. The former requires one to quantify saturation and pressure effects on rock elastic parameters. The latter requires an understanding of the combined response of time-lapse effects in thin layers and overcoming seismic vertical resolution limitation.This thesis presents an integrated study of saturation and pressure effects on elastic properties. Despite the fact that Gassmann fluid substitution is standard practice to predict time-lapse saturation effects, its validity in the field environment rests upon a number of assumptions. The validity of Gassmann equations, ultimately, can only be tested in real geological environments. In this thesis I developed a workflow to test Gassmann fluid substitution by comparing saturated P-wave moduli computed from dry core measurements with those obtained from sonic and density logs. The workflow has been tested on a turbidite reservoir from the Campos Basin, offshore Brazil. The results show good statistical agreement between the P-wave elastic moduli computed from cores using the Gassmann equations and the corresponding moduli computed from log data. This confirms that all the assumptions of the Gassmann theory are adequate within the measurement error and natural variability of elastic properties. These results provide further justification for using the Gassmann theory to interpret time-lapse effects in this sandstone reservoir and in similar geological formations.Pressure effects on elastic properties are usually obtained by laboratory measurements, which can be affected by core damage. I investigated the magnitude of this effect on compressional-wave velocities by comparing laboratory experiments and log measurements. I used Gassmann fluid substitution to obtain low-frequency saturated velocities from dry core measurements taken at reservoir pressure, thus mitigating the dispersion effects. The analysis is performed for an unusual densely cored well from which 43 cores were extracted over a 45 m thick turbidite reservoir. These computed velocities show very good agreement with the sonic-log measurements. This is encouraging because it implies that core damages that may occur while bringing the core samples to the surface are small and do not adversely affect the measurement of elastic properties on these core samples. Should core damage have affected our measurements, we would have expected a systematic difference between properties measured in situ and on the recovered. This confirms that, for this particular region, the effect of core damage on ultrasonic measurements is less than the measurement error. Consequently, stress sensitivity of elastic properties as obtained from ultrasonic measurements are adequate for quantitative interpretation of time-lapse seismic data.In some circumstances, stress sensitivity may not be obtained by ultrasonic measurements. Cores may be affected by damage, bias in the plugging process and scale effects and therefore may not be representative of the in situ properties. Consequently it is desirable to obtain this dependence from an alternative method. This other approach ideally should provide the pressure - velocity dependence from an intact rock. Few methods can sample the in situ rock. Seismic, for instance, provides in situ information, but lacks vertical resolution. Well logs, on the other hand, can provide high vertical resolution information, but usually are not available before and after production changes. I propose a method to assess the in situ pressure - velocity dependence using well data. I apply this method to a reservoir made up of sandstone. I used 23 wells drilled and logged in different stages of development of a hydrocarbon field providing rock and fluid properties at different pressures. For each well logged at a specific time, pore pressure, velocity and porosity, among other properties, are known. Pore pressure is accessed from a Repeat Formation Tester (RFT). As a field depletes and new wells are drilled and logged, similar data sets related to different stages of depletion are available. I present an approach expanding Furre et al. (2009) study incorporating porosity and obtaining a three dimensional relationship with velocity and pressure. The idea is to help to capture rock property variability.Quantitative time-lapse studies require precise knowledge of the response of rocks sampled by a seismic wave. Small-scale vertical changes in rock properties, such as those resulting from centimetre scale depositional layering, are usually undetectable in both seismic and standard borehole logs (Murphy et al., 1984). I present a methodology to assess rock properties by using X-ray computed tomography (CT) images along with laboratory velocity measurements and borehole logs. This methodology is applied to rocks extracted from around 2.8 km depth from offshore Brazil. This improved understanding of physical property variations may help to correlate stratigraphy between wells and to calibrate pressure effects on velocities, for seismic time-lapse studies.Small scale intra-reservoir shales have a very different response from sands to fluid injection and depletion, and thus may have a strong effect on the equivalent properties of a heterogeneous sandstone reservoir. Since shales have very low permeability, an increase of pore pressure in the sand will cause an increase of confining pressure in the intra-reservoir shale. I present a methodology to compute the combined seismic response for depletion and injection scenarios as a function of net to gross (NTG or sand – shale fraction). This approach is appropriate for modelling time-lapse effects of thin layers of sandstones and shales in repeated seismic surveys when there is no time for pressure in shale and sand to equilibrate. I apply the developed methodology to analyse the sand - shale combined response to typical shale and sandstone stress sensitivities for an oil field located in Campos Basin, Brazil. For a typical NTG of 0.6, there is a difference of approximately 35% in reflection coefficient during reservoir depletion from the expected value if these shales are neglected. Consequently, not considering the small shales intra-reservoir may mislead quantitative 4D studies.The results obtained in this research are aimed to quantify pressure and saturation effects on elastic properties. New methodologies and workflows have been proposed and tested using real data from South America (Campos Basin) datasets. The results of this study are expected to guide future time-lapse studies in this region. Further investigations using the proposed methodologies are necessary to verify their applicability in other regions

RESERVOIR CHARACTERISATION AND STRUCTURAL INTERPRETATION FOR PROSPECT EVALUATION- A CASE STUDY

This paper presents a case study dealing with reservoir delineation and characterisation of the Basecopia field, part of Niger Delta Nigeria. The data set utilized for this work incorporate 3D seismic data, well log suites containing gamma rays, resistivity and porosity logs (neutron and density). These logs were utilized to focus petro-physical properties in three (3) wells. 780 inlines and 496 crosslines of seismic information covering an area of about 234 km2 were utilized. Faults were picked and correlated. Horizons of hydrocarbon bearing sands were picked in view of the re-suit from seismic- to-well tie. These were utilized to produce time and depth maps for a horizon keeping in mind the end goal to recognize the different basic highlights inside the field. Petro-physical aftereffects of the study demonstrate the dominating liquid found in the three wells is light oil at True Vertical Depth Sub Surface (TVDSS) of -7109 to -7333 ft. in Well A, -6916 to -7044 ft. in Well B and -7694 to -7858 ft. in Well C. Thereafter, seismic attributes such as the instantaneous frequency and the dominant frequency indicated the presence of channel filled sand containing hydrocarbon in regions around the wells. Hence, the wells can be said to be properly situated within the reservoir hydrocarbon bearing sand with spatial facies evenly distributed. The study however concluded that Well A bears a considerable amount of reserves of about 209.52Mbbl

Deterministic and stochastic inversion techniques used to predict porosity: A case study from F3-Block

Within large-scale sigmoidal bedding of the F3-block in the shallow zone there appear to be some indicators of hydrocarbon deposits. In order to characterize target zone in the sigmoidal bedding, I combine the analysis of inverted results of post-stack seismic data with rock-physics relationships developed from well log data to predict the porosity, which ranges from 20% to 33%, for different system tracts in this area. The methods used in this study include conventional deterministic inversion and novel stochastic inversion. Through a rock physics analysis of the density, velocity and gamma-ray logs in two wells, I constructed relationships between the acoustic impedance and porosity; one is appropriate for the high-stand (more shale-prone) system tract, and one for the low-stand (more sand-prone) system tract. With the help of these two inversion methods and the two impedance-porosity relationships, four high-resolution porosity models have been generated providing insight into potential high-porosity and potential hydrocarbon-bearing zones