Inversion EEI (Whitcombe et al., 2002) that allows the generation of compressional velocity, shear velocity, density, and various elastic and petrophysical ...
Introduction With the extensive use of advanced seismic technologies, it is possible to enhance the drilling success rate of a company. These technologies lead to the discovery of mega fields. These mega fields are found along with many others smaller fields under the salt layer found in the continental shelf offshore South America. Among these smaller fields, we will be focusing in this study on a recently discovered subsalt field located in the Campos Basin. The field is producing from an aptian carbonate platform. The high energy facies along rimmed platform margin show good rock properties while poor rock filled with clay can be found in the tidal channel areas. The dominant facies present in the considered area are limestone and shale. The key rock properties such as porosity and permeability vary considerably in the considered area. For example the porosity could be as low as 2-3 % and as high as 30 % while the permeability could vary from zero to many Darcies. This high permeability is the result of two additive components: a matrix that could have in some areas large macropores that provide very high matrix permeability and fractures that could enhance the existing matrix permeability or simply create permeability in tighter matrix zones. The modeling of these key rock properties is critical to the building of a reservoir model that could be used to design an optimal development plan. Because these wells are 4000 m deep and the water column is 700 m, the investment required to develop these fields is very important, thus the need to reduce dramatically the risk. This reduction in risk could be achieved by reducing the uncertainties through the extensive use of modern seismically driven reservoir characterization workflows. The workflows available in CRYSTALTM are applied to this field. Geophysical Modeling The available seismic data along with 5 wells that have many modern logs, were used in the following processes: seismic resolution enhancement, seismic-well ties, volumetric curvature, spectral imaging and highresolution post-stack inversion and pre-stack extended elastic inversion. In this project, a resolution enhancement (Mundim et al., 2006) was applied to the post stack seismic and lead to a substantial boost of frequencies between 30 and 60 Hz thus increasing the dominant frequency by at least 15 Hz. This increase in resolution will be very beneficial for the structural interpretation, the well ties, and the generation of seismic attributes. Using the derived enhanced seismic and the available sonic and density logs well ties were completed at all the wells. The first process that will benefit from this enhanced resolution is volumetric curvature attributes able to highlight key structural features. In the considered field the most negative curvature is one of the best volumetric curvature attribute used to image the faults. The next seismic process applied to the enhanced seismic is spectral imaging. The resulting seismic attributes are frequency dependent or represent statistical properties that describe the behaviour of the seismic power spectrum at different frequencies. Various post stack inversion algorithms were applied to this field. These inversions are divided into two categories: deterministic and stochastic. For reservoir and fracture modeling where vertical resolution is critical, the stochastic inversion remains the best approach since it provides the means to derive an impedance model at a resolution of 0.5 ms to 1 ms. Prior to any seismic inversion, a tight structural framework is needed to account for the faults and their offsets. For this field, 5 horizons and 156 faults were used to build the structural framework in the time domain. Given the structural framework and the well ties, multiple deterministic inversions were run first followed by the stochastic inversion which uses a deterministic impedance as a soft constraint.
Although post-stack attributes are very useful and have shown in the past (Hamad, et al. 2010) their ability to create very reliable fracture models, the use of pre-stack elastic inversion provide direct indication on key rock properties critical for a successful fracture modeling effort. In this project we used the Extended Elastic Inversion EEI (Whitcombe et al., 2002) that allows the generation of compressional velocity, shear velocity, density, and various elastic and petrophysical parameters from the seismic data. Three partial angle stacks – near (4-13 degrees), mid (13-22 degrees), and far (22-31 degrees), were used in this study to derive the usual elastic properties but also important petrophysical properties such as gamma ray, Uranium concentration, porosity, and water saturation. The use of the Chi (χ) angle in EEI to derive directly from pre-stack seismic rock properties First EAGE/ SBGf Workshop on Fractures in Conventional and Unconventional Reservoirs 5-6 November 2013 Rio de Janeiro, Brazil
that have a direct impact on fracturing has shown in the past (Bejaoui et al., 2010) dramatic benefits and improved fracture models that were able to lead to dynamic models that matched the complex well performance history with very minimal history matching effort. The same EEI benefits were also found in this project. To be able to use the seismic attributes in geologic and fracture modeling, a 3D geocellular grid is built in the time domain. The derived structural framework is divided into rectangular cells that are 87.5 m x 87.5 m in the areal direction. Twenty five layers with an average thickness of 3.7 m are used to capture the vertical heterogeneities of the main producing reservoir. The resulting 3D geocellular grid has almost 900,000 cells. With the 3D geologic grid available in the time domain, all the derived seismic attributes could be snapped and made available to the geologic and fracture modeling upcoming effort. The final step before starting the geologic and fracture modeling effort is the conversion to depth of the 3D geocellular grid. This is achieved by using multiple velocity models to assess the uncertainties related to the depth conversion. This time-to-depth conversion will provide for each velocity model an equivalent 3D geocellular grid in the depth domain along with all the snapped seismic attributes. Sequential Geologic Modeling Given that many seismic attributes contain valuable geologic information and could be very beneficial, the use of a neural network approach is more appropriate for geologic and fracture modeling. In this project, a sequential geologic modeling approach (Ouenes et al. 2007) is used to estimate various geologic and fracture models. The neural network will use the available well log data to find possible relationships between petrophysical properties and the multitude of available seismic attributes. Once these relationships are found with a subset of the well data during the training process, they will be tested on another subset not seen by the neural net during the training. The best neural network realizations able to have predictive capabilities on the testing subset are kept for further validation. Blind wells not used at all in the neural network training and testing process are used to select the best neural network realizations for prediction purposes.
In the considered carbonate field, the best well properties are derived from the analysis of the image logs and NMR logs. The six major rock properties derived in a sequential manner are: 1) Uranium concentration, 2) facies model, 3) net to gross ratio, 4) NMR porosity, 5) water saturation, and 6) matrix permeability. The derived Uranium concentration model was estimated by using a multitude of seismic attributes. After accumulating all possible and meaningful geologic models, the modeling of the fractures could be initiated. Continuous Fracture Modeling (CFM) The CFM approach (Ouenes, 2000, Jenkins, et al., 2009) uses a neural network to correlate the fracture density available at the wells with all the geophysical and geologic drivers derived previously and available in 3D as geocellular models. Many fracture density realizations were generated and analyzed to better understand their vertical and areal distribution. Two sets of fractures are present in the wells that had image logs: N70E and N30E. The dominant fracture orientations predicted by the CFM models, (which does not use known well fracture orientations as input in the fracture modeling effort), matched correctly these orientations. Given that the SHmax is W-NW, these fracture models and their predicted dominant fracture orientations could provide critical information for potential water encroachment problems and help drill wells oriented in the optimal direction that could prevent rapid water arrival. This issue requires the building of a dynamic model.
Model Validation with Dynamic Models The matrix porosity model estimated from the sequential geologic modeling as well as an effective permeability that combines the effect of matrix and fractures was used in EclipseTM in a single porosity / single permeability system. The dynamic model contains two rock types related to the Uranium concentration. In each rock type a set of flow functions and effective permeability model is assigned. The key reservoir parameter for the dynamic model is the effective permeability computed as follows: K eff = C1· (K m + C2 · f ) where Keff : Effective permeability of the combined matrix and fracture flow,
K m : Matrix permeability, f
: Fracture density, and C1 and C2: Scaling factors to be estimated by history
matching. Using the total liquid as a constraint, the match of the pressure and water cut as well as the oil rate First EAGE/ SBGf Workshop on Fractures in Conventional and Unconventional Reservoirs 5-6 November 2013 Rio de Janeiro, Brazil
was achieved at the two producing wells. The good match of the wells confirms the ability of the derived model to account for the complex fracture network and its effect on the existing matrix
Conclusion The extensive and simultaneous use of high resolution pre and post stack seismic attributes in the sequential geologic modeling approach followed by the continuous fracture modeling lead to reservoir models that utilize quantitatively all the available data. Consequently the resulting dynamic model are able to reproduce the current reservoir behaviour as seen in well tests and well production history thus providing enough confidence for developing reliable future development plans. Acknowledgements The authors would like to thank PETROBRAS for authorizing the publication of this paper. The authors are grateful to the contribution of many PETROBRAS and SIGMA3 geoscientists who participated in this project. The efforts of Chelsea Newgord, Eric Bard, Dave Balogh, Stefanie Aurelio, Badia Daoudi, Mohamed Mediani, Djamel Boukhlef, Aissa Bachir, Marcos Paulo Aguiar de Deus, Vítor da Silva Novellino, Mário Sérgio dos Santos Braga and Marcus Vinícius Leitão de Figueiredo are greatly appreciated. References Bejaoui, R. Ben Salem, R., Ayat H., Kooli, I., Balogh, D., Robinson, G., Royer, T., Boufares, T., Ouenes, A., [2010] Characterization and simulation of a complex fractured carbonate field offshore Tunisia, paper SPE 128417 Hamad, M., Shahlol, A., Hajaj, S., Aoues, A., Ouenes, A., El Werfali, H, BuArgoub, F., Kirkham, A. [2010] Seismically driven characterization of vuggy porosity and fractures in a carbonate field, Sirte Basin, Libya, First Break, Vol 28. Jenkins, C., Ouenes, A., Zellou, A., Wingard, J. [2009] Quantifying and predicting naturally fractured reservoir behavior with continuous fracture models,” AAPG Bulletin, V. 93, No 11. Mundim, E.C. Sohots, H.A., De Araujo, J. M., Tavares, D. M, [2006], WT decon, a colored deconvolution implemented by wavelet transform, The Leading Edge, April. Ouenes, A. [2000] Practical application of fuzzy logic and neural networks to fractured reservoir characterization, Computers and Geosciences, Shahab Mohagegh (Ed.) v. 26, no 7. Ouenes, A., et al. [2007] Integrated Property and Fracture Modeling Using 2D Seismic Data: Application to an Algerian Cambrian Field, paper SPE 109272 Whitcombe, D.N., Connolly, P.A., Reagan, R.L., and Redshaw, T.C. [2002] Extended elastic impedance for fluid and lithology prediction, Geophysics, 67, pp. 63-67.
First EAGE/ SBGf Workshop on Fractures in Conventional and Unconventional Reservoirs 5-6 November 2013 Rio de Janeiro, Brazil
