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Collaborating Authors
Results
Abstract The facies and net-to-gross ratio (NTG) modeling methodology presented in this paper has been successfully applied on geological characterization of a giant field at Campos Basin, offshore Brazil. Such methodology aimed to preserve the seismic attribute original trend for NTG property in the facies model. In this way, more reliable horizontal parameters could be determined. These are usually hard to obtain, due to the scarceness and huge spacing between wells in an oilfield at its initial development stages. The technique may be described as follows:Choice of a seismic attribute that shows good correlation with average NTG at wells using programme Log Property Mapping (SIS-Schlumberger Information Solutions). After that one must elaborate a non-reservoir average distribution map (NR=1-NTG map). Generation of reservoir facies proportion maps (three altogether) obtained by facies proportion interpolation at the wells (collocated co-Kriging) using the NTG distribution map as a secondary variable. Determination of horizontal variogram parameters. These are used in the non-reservoir facies simulation (from NTG distribution map) and correlated with vertical variogram range, obtained from well data. Determination of horizontal variogram parameters for each of the three reservoir facies using ratios between horizontal variograms range (two directions) and the vertical ones. Determination of NTG, naming 1 for reservoir facies and 0 for non-reservoir facies. In the modeling phase, mainly in the upscaling step, a particular interval named inter-stratified has been given special treatment. It shows a NTG value around 50% (against a 85% value for the field as a whole) and has been defined in order to preserve the critical reservoir heterogeneities. Once treated in a different way during the upscaling step, its characteristics can be preserved during the scale transfer, and consequently improving history match. Introduction Facies model building may be constructed by two main methods: pixel based (Kriging, SGS) or object based. The choice for the best one depends upon the available information, the characteristics and the geological knowledge about the field. The input data for both is known as the hard data (e.g. wells and facies proportion), which must be respected during simulations, and the soft data (e.g. seismic attributes, variogram parameters), which are used as trends and have differentiated weights within simulations. As a result, each of these methods come up with distinct architecture and facies distribution. This paper intends to describe the phases in the facies and net-to-gross ratio (NTG) modeling (conditioned by maps obtained from seismic attributes) and its use in the upscaling phase in a giant field at Campos Basin. The methodology aims to embrace and preserve the seismic attribute trend for NTG within the facies model itself taking into account facies proportion maps and variograms used in geostatistical simulation. The reservoir is made up of turbiditic sandstones and conglomerates. The main zone may be divided in two stratigraphic subzones: upper and lower. The lower subzone is composed of sandstones and conglomerates deposited in a turbidite channel system. The upper, deposited in a less confined setting, is composed of finer sandstones and intercalated shales. Previously both subzones were thought to be communicated, but after the pilot production started, a differential depletion has been observed between them, indicating that must indicate that the hydraulic vertical communication shows a certain degree of restriction. It has been attributed to an interval named inter-stratified (Inter) that presents a NTG around 50% (against a 85% value for the field as a whole) and located right on lower subzone. Although it is a meaningful heterogeneity such interval cannot be mapped by seismic and it is essential that its characteristics be preserved when the geological grid is upscaled into the simulation one. In order to keep its characteristics and to come to a better production history match the interval was individualizaed within the geological model and treated differently in the upscaling step.
- South America > Brazil (1.00)
- North America > United States > Texas (0.47)
Using Seismic Attributes in Petrophysical Reservoir Characterization
Costa, Flaviana Almeida (Petrobras) | Suarez, Carlos Rodriguez (Petrobras) | Sarzenski, Darci Jose (Petrobras) | Ferreira Guedes, Carlos Conforti (Petroleo Brasileiro S.A. - Petrobras)
Abstract The use of seismic attributes has increased, especially when extracted from interpreted horizons. The various available attributes are not independent from each other but represent, in fact, different ways of presenting and studying fundamental information from seismic data (time, amplitude, frequency and attenuation). However, statistical analysis using attributes must be based on geological knowledge and not only on mathematical correlation. Petrophysical studies and seismic modeling are sources of understanding. Such knowledge is necessary to improve confidence in observed correlations with reservoir parameters and must be part of all attribute analysis. However, the use of seismic attributes leads to several questions, for example, what do they all mean? When to use one or another? How to use them on geologic modeling? How reliable those data are? The answers to these questions are not easy, but considering about petrophysical modeling (Porosity, NTG and permeability) what is the best approach: to consider only well data, that are punctual and need to be interpolated, or try to find correlation with physical measurements (seismic data)? Not to consider seismic attributes makes one feel coming back in time, when this important tool was not available. On a giant oilfield offshore Brazil seismic attributes ('conventional', complex trace, polynomial decomposition, geometric and coherence) have been used to create geological models and to reduce uncertainties. The attribute choice must be performed by the geophysicist and the geologist working together, in order to check geological meaning of attribute maps, possible physical meaning of the attribute, etc. Plots of the highest correlation values should be visually inspected in order to choose the attribute with best correlation to the desired parameters. The results show attributes have been favourable to porosity and NTG prediction, but regular (at maximum) to permeability. For permeability even if the results are not so good, the correlation are improving for the latest models (as long as new wells are used). Polynomial decomposion and complex trace attributes have shown better results. Introduction: seismic attribute definitions and discussions The use of seismic attribute data for prediction of detailed reservoir properties began more than 30 years ago. In fact, a seismic attribute is any property derived from seismic reflection signal. Attributes may be compared to lithology in an attempt to devise a method of property prediction away from well control. The method of prediction can vary from a simple linear correlation to multi-attribute analysis, geostatistical methods, etc. As an evidence of current proliferation the use of attributes, Chen and Sidney (1997) have catalogued more than 60 commom seismic attributes along with a description of their apparent significance and utility. Although there is a rich history of seismic attributes use in reservoir prediction, the practice remains a difficult and uncertain task. The bulk of this uncertainty arises from the nature of the physics connecting a number of attributes to a corresponding reservoir property. Due to the complex and varied physical processes responsible for various attributes the unambiguous use of attributes for direct prediction will probably remain a challenge for the years to come. In addition to the fact above described, there is the possibility of coming across statistical pitfalls while using multiple attributes for empirical reservoir property prediction. In addition, many attributes are derived using similar signal processing methods and can, in some cases, be considered largely redundant with respect to their description of the seismic signal.