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First EAGE/AMGP/AMGE Latin-American Seminar in Unconventional Resources
- Conference date: November 23-24, 2017
- Location: Mexico City, Mexico
- Published: 23 November 2017
1 - 20 of 40 results
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Linking the Emerging Mexican Eagle Ford Shale in Burgos Basin with the Eagle Ford in Texas
Authors M. Cruz and R. AguileraSummaryThe technical and economic success in the Eagle Ford shale in Texas with horizontal wells and multi-stage hydraulic fracturing jobs and the ongoing reform in Mexico have created high expectations about the development of the well-known shale formation south of the border in Mexico.
Integration of geologic, geochemical, petrophysical and production data is a key for a proper characterization when dealing with unconventional reservoirs. In this study, some of the wells that corroborated continuation of Eagle Ford in Texas and Burgos basin, such as Emergente 1, Habano 1, and Montañés 1 are examined on light of recent advances in the evaluation of shale reservoirs using geoscience and engineering data.
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Petroleum Systems Modeling in Unconventionals
More LessSummaryThe success of any exploration campaign depends on the convergence of crucial geologic elements/processes and requires a methodology to predict the likelihood of success given the available data and associated uncertainties. Basin and petroleum system modeling allows geoscientists to examine the dynamics of sedimentary basins and their associated fluids to determine if past conditions were suitable for hydrocarbons to fill potential reservoirs and be preserved there.
More than 50 years ago, geologists began building the foundation for a concept that has since evolved into such a predictive methodology. The concept connects the past—a basin, the sediments and fluids that fill it, and the dynamic processes acting on them—to the present: Petroleum Systems Modeling. This area of study, applies mathematical algorithms to seismic, stratigraphic, paleontologic, petrophysical, well log and other geologic data to reconstruct the evolution of sedimentary basins.
The application of these methodologies has been successful during years; however, with the emergence of unconventional plays, it has become common practice to extrapolate methodologies applied historically in conventional fields for non-conventional areas. This assumption can be extremely risky considering the great differences between these plays and the economic decisions that this analysis of potential may have.
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Organic Richness Evaluation through Empirical Methods and Neural Networks
By F. JuarezSummaryFrom a petrophysical point of view, organic shales are unique and complex formations since play both source and reservoir roles in the petroleum system. Because of this, it is important to compute the total organic carbon content of these formations and convert it to kerogen volume. In order to achieve it, there are many empirical methods developed for different US shale plays. In the current case of study, some of the well-known methods were applied to an Eagle Ford well and the outputs were calibrated to Rock-Eval 6 core data. Thermal maturity was inferred too by means of the pyrolysis results. Furthermore, a neural network for TOC computation was built and the results were statistically compared each other, and the best output was converted to kerogen volume, one of the most important inputs in the subsequent steps in the petrophysical evaluation of organic shales
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Risks and Uncertainties of Shale Gas Plays at New Venture Scale
Authors A. Pastor and J. FerrandSummaryAs the name reflects, the Unconventional Resources are different and should be study in a different way. There is no clear “killing” factor like in the conventional world. It is important to take into account all the parameters together (one could compensate another one). Keeping that in mind never try to kill a project too soon. Most of the unconventional “reservoirs” will flow hydrocarbons if stimulated, the real killing factor is at what cost.
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Joint Hydrodynamic Sectioning Method and Logs for Determining Mud Shale Organic Carbon Content
Authors W. Liu, Z.Y.S. Zhang, C.F. Cheng and Y.G. YuSummaryAs the organic carbon content directly influences the optimization of shale gas exploration zones, an in-depth evaluation on organic carbon content is particularly important. At present, the most common method for determining the organic carbon content in the mud shale is the ΔlogR method, which is lose sight of the hydrodynamic conditions and sedimentation environment, such as underwater disturbance and oxygen content difference, the difference in preservation conditions for organic matters. Those can lead to in great variation in the organic carbon content. This paper introduces the evaluation technique for the organic carbon content in the mud shale.
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Lessons Learned in Developing a Giant Low-Permeability Conglomerate Reservoir
Authors L. Jiahong, X. Yuxiang and H. XiulinSummaryThis paper studied a giant tight conglomerate reservoir of a developing history for 40 years. Reasons behind its poor performance were analyzed. Through the analysis, 3 lessons in the past were summarized for similar reservoirs all around the world to learn. Last, the potential remained ahead were pointed out.
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3D Seismic Acquisition Technology and Effect of Complex Mountainous and Tectonic Areas in Shale Gas Play of China
Authors W. Liu, Z.Y.S. Zhang, Y.G. Yu, Z.J.J. Zhang and H.C.J. HuSummaryThe geological structure is very complex; the formation shows typical structural style feature of septum; and the burial depth and dip angle of the shale formation change dramatically.
In this paper, we introduce a shale gas formation 3D seismic survey geometry design and optimization with wide azimuth, moderate bin size, high fold number, long spread and relatively even sampling for the prediction of the important reservoir parameters such as fault, fissures, TOC, brittleness and pressure coefficient, and estimating and evaluating the distribution of shale gas sweet spots. These information have guided the horizontal well location selection and well trajectory design optimization effectively for several exploration and production blocks of marine shale gas in the mountain area of South China.
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Zero Offset, Vertical Incidence and Time-Lapse Walkaway VSP in the Eagle Ford
Authors A. Bernaola, L. Linares and J. TeffSummaryA time-lapse seismic survey is one of the tools to monitor changes in the reservoir’s properties over time. In this case study 2D images before and after an hydraulic fracture in the Eagle Ford formation were created from walkaway VSPs with the objective of identifying the zone affected by the treatment. The study was completed with a walkabove VSP to detect potential fractures below the wellbore that could divert the hydraulic fluid and a shear wave zero offset VSP to determine the direction of the natural fractures. This information was used in the design of future hydraulic fracture programs for wells in the area.
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High Resolution Diffraction Imaging for Reliable Interpretation of Fracture Systems
By B. de RibetSummaryNatural fractures in shale formations can provide a pathway for higher permeability; therefore, they need to be characterized. The characterization of small-scale features is a challenge when dealing with conventional seismic methods. Seismic resolution has limitations for understanding sub-seismic scale structural patterns, stratigraphic variations and reservoir heterogeneities.
Minor fault trends, stratigraphic edges and fractures represent scattering sources for seismic wave propagation. The wavefield generated by those source points is identified as diffraction energy. This energy is always registered during seismic acquisition, but suppressed by standard processing sequences and imaging algorithms. The method explained in this paper is based on an imaging algorithm that maps the recorded surface information into the local angle domain (LAD). The differentiator of this method is its ability to preserve the wavefield through decomposition into reflection and diffraction energy. This paper shows the benefits of LAD technology when applied to the Eagle Ford play in South Texas, where seismic data can be of moderate quality, leading to accurate, high-resolution, and high-certainty seismic interpretation for risk management in field development.
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Application and Importance of Orthorhombic AVAZ Inversion
By E. GoferSummaryAmplitude variation with azimuth (AVAZ) analysis plays an important role in characterizing both conventional and unconventional reservoirs. The AVAZ technique can provide information about stress and/or existing fractures in the reservoir, thus improving the ability to identify sweet spots and optimize drilling and fracking processes. In the case of fractured reservoir, orthorhombic symmetry can be considered the simplest realistic rock model. The unfractured reservoirs and shale, in particular, can be approximated as a transversely isotropic media with vertical symmetry (VTI). Adding a vertical fracture set to a VTI background rock results in orthorhombic symmetry. Unconventional reservoirs can also display strong reflectivity due to strong contrast between the layers. This is often seen in reservoirs located below high-velocity carbonates. Linearized AVAZ equations assume weak anisotropy and small contrast interfaces. as a results the linearized approximation of the PP-reflectivity will not adequately represent the AVAZ response and nonlinear Zoeppritz equations are required to model the PP-reflectivity correctly. This presentation will focus on the importance and the application of the orthorhombic AVAZ inversion and inversion results from examples from the unconventional play in the Middle East and North America will be shown.
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Seismic Inversion for Engineering Applications in Unconventional Reservoirs
By C.M. SayersSummaryEconomic production from unconventional reservoirs requires increasing the surface area in contact with the reservoir via hydraulic fracturing. Important to the design of efficient hydraulic fractures is knowledge of the orientation and magnitude of principal stresses, geomechanical rock properties, and the density and orientation of any natural fractures. The use of seismic AVOAz (Amplitude Variation with Offset and Azimuth) inversion to determine fracture density and orientation as well as horizontal stress anisotropy and the orientation of the principal stresses is illustrated using examples from the Middle East and North America. An example is shown of using the results of seismic AVOAz inversion calibrated to geomechanical measurements on cores, to build a 3D MEM (Mechanical Earth Model) for an area in North America. The variation in principal stresses over the area is evaluated using the Finite Element Method. Computed stresses are found to be consistent with variability in production over the area and show stress rotations near faults in agreement with microseismic data.
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Integrated 3D Seismic Attributes with Microseismic to Estimate Shale Plays
Authors W. Liu, ZYS. Zhang, Y.G. YU, C.F. Cheng and L.T. LiSummaryHydraulically induced micro seismic fractures can be used to increase reservoir permeability, which is an important process in the shale gas exploration & development. Micro seismic monitor can be used to estimate induced fracture’s orientation and fracture’s size, guiding completion design. However, micro seismic events are affected by many factors. How to understand micro seismic events characteristic is very important for the reservoir construction. In this paper, we try to understand,(1) why are the micro seismic events different for the adjacent well.(2) Why there are a lot of big energy events above the target layer?(3) For the micro seismic events, the more, the better? We introduced the 3D seismic attributes to evaluate micro seismic events and summarized a set of methods to solve some engineering problems.
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Data Analytics: An Innovative Tool for Unconventional Plays
Authors J.F. Granados and M.H. CamposSummaryExtracting hydrocarbons from unconventional reservoirs using horizontal drilling and multi-stage fracking is more complex and generates more data than traditional E&P activities. Accordingly, shale focused operators and investors are no longer able to maximize their competitive advantage using conventional data analysis techniques. This works presents the general characteristics of new analytics tools that allows operators to predict production maps and volumes. These tools also provides the ability to compare a variety of geological, geophysical, drilling, and completion parameters with results from areas with varied production.
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Sweet Spot Interpretation from Multiple Attributes: Machine Learning and Neural Networks Technologies
Authors R. Guo, Y.S. Zhang, H. Lin and W. LiuSummaryThe “sweet spot” interpretation of shale gas routinely involves advanced visualization techniques, and generation of numerous seismic data types and attributes. Commonly used seismic attributes include the total organic carbon content (TOC), pore pressure, stresses, rock elasticity, brittleness and fracture development. To derive even more useful information from the multiple attributes and provide a easily tool for the characteristic analysis of the target shale reservoir, current visualization techniques, machine learning and neural networks technologies, including self-organizing map (SOM), K-means clustering, principal component analysis (PCA) and two-dimensional HSV color map have been all introduced to reveal the geologic features that are not previously identified or easily interpreted from the numerous seismic attributes. Through the attribute patterns generated by SOM, the unsupervised (K-means clustering), supervised (human-computer interaction monitoring clustering) classifications can be applied for flexibly explaining the characteristics of “sweet spot”. Integrating with the PCA and HSV color map techniques, the distribution in the attributes selected are intuitively reflected and described.
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Intergrated Sweet Spot and Microseismic Monitor to Optimize Reservoir Stimulation: A Wolkflow for Shale Gas, China
More LessSummaryResearch shows, shale gas production impaction factors exist mainly two types, one is seismic factor (e.g. Total organic carbon, brittleness, core pressure, fractures, stress etc.), the other is engineer factors (e.g., micro seismic monitor, fracturing schemes), Single factor, seismic or engineering factors often preferred not guarantee shale gas highly production, only when the most optimal combination of both, can achieve shale gas production maximization. How to integrate seismic and engineering factors for a comprehensive assessment of shale reservoirs it? We tried to find a solution: (1)how to use the geophysics results to guide unconventional hydraulic fracture?(2) how to integrate sweet spot and engineering factors to guide shale gas exploration and development, reducing engineering damage, such as casing deformation, sand blocking, realizing shale gas production capacity maximum.
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Shale Gas Reservoir Characterization and Sweet Spot Prediction
Authors G. Yu, Y.S. Zhang, X.M. Wang, W. Liu and R. GuoSummaryThe characterization of shale gas formation is rapidly gaining prominence as a result of the increasingly important role of unconventional reservoirs in South China. Engineering practices such as horizontal drilling and hydraulic fracturing in shale gas formation has created a need for volumetric quantification not only of fracturing but of other geomechanical properties such as Young’s Modulus, Poisson’s Ratio, and maximum horizontal stress direction, in addition to more conventional reservoir properties such as lithology, brittleness, TOC and porosity as input for reservoir simulations. An integrated study of the well Zhao-104 and surrounding wide-azimuth 3D seismic volume within the shale gas reservoir in South China has been conducted with the objective of generating shale formation properties related to fracture orientation and intensity in the area and deriving such reservoir rock properties. The multi-attribute data fusion process to integrate all “sweet spot” parameters, such as shale formation depth, thickness, fault and fracture zone intensity and distribution, TOC and its thickness distribution, local stress field and its orientation, formation brittleness, pressure coefficient, impedance, Passion’s ratio, Young’s modules, porosity distribution, was used to predict “sweet spot” for shale gas reservoir exploration and production.
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Use of High Resolution Seismic for Generation of Seismic Production Forecasting Models
By C. MorenoSummaryGeneration of seismic production forecasting models, based on integration of geological, geophysical and engineering data has proven to be a powerful tool to characterize and identify sweet spots or areas of better performance in unconventional reservoirs.
Integration of geological, geophysical and petroleum engineering data can be a difficult task because they measure differently dynamic and static properties of reservoirs components with very different sampling metrics and units. Traditional multidisciplinary workflows accepted by the industry are very lengthy and costly, however they are worth doing due to the benefit they bring. Production Forecasting Models are not intended to replace typical workflows but they are intended to help multidisciplinary teams having alternatives during the development and infill drilling planning. The turnaround time and relative low cost to generate seismic production forecasting models make them a great tool to consider in the field development planning.
Seismic production forecasting models are a way to “predict barrels of oil (cumulative production at certain time frame from completion of wells) directly from seismic amplitudes”. Calibration and validation with existing production data is required during the process. It is also constrained and validated with seismic data, well data (logs, tops, etc), core data, microseismic data and engineering data (perforations, stages information, production/well or stage). No data should be ignored in building a model like this.
When an outcome of interest is affected or influenced by more than one attribute the use of techniques like multiattribute statistical analysis is desirable. In the case of production forecasting based on seismic attributes it has been found that the multiattribute statistical analysis technique provides robust results. It has been found that not a single conventional seismic attribute can be related to production however the combination of many of them with other geological and engineering can improve the prediction based on seismic data.
Increasing the seismic resolution of conventional seismic has shown also to be a very powerful tool in the workflow. It helps describe better the heterogeneities of unconventional reservoirs. There seem to be strong lateral and vertical changes on production performance of unconventional reservoirs that can be explained with seismic heterogeneities predicted with increasing the seismic resolution using techniques like sparse layer inversion. In this article, we show the results of a workflow for generating production forecasting models based on properties extracted from high resolution seismic. The models were generated using multivariate statistical analysis.
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Stress Organization along Neuquen Basin in Vaca Muerta Formation and their Impact in Microseismic Response
Authors Y. Sanz Perl and D. DelucchiSummaryThis work presents the results of the analysis of stresses organization that includes the Shmax orientation and 1d geomechanical model information. The borehole breakouts and drilling induced tensile fractures (DITF) from wells within Total Austral blocks and surrounding areas in Neuquen Basin (Argentina) were used to compute Shmax orientation. This analysis was complemented with information obtained from World Stress Map Project and previous works [e.g. Guzman et al., 2007 ]. The results show a regional anticlockwise rotation of the SHmax from south to north of the Neuquen Basin.
The 1D geomechanical stresses model was computed in Total Austral wells and using to compute the ratios Shmin /Sv and Shmin /Shmax representing the stress regime and the horizontal stress anisotropy respectively.
The results show variations of stress regimes from strike-slip to thrust and a decrease of the stress anisotropy from south to north. These variations lead to different microseismic responses and allow characterizing in terms of hydraulic fracture creation the selected landing point in each area.
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A New Pressure Prediction Method of Southern China Shale Reservoir
More LessSummaryThis new pore pressure prediction approach uses Eaton’s Principle combined with the Fillippone formula for calculation. For complex surface structure in the shale gas in Southern China, its feasibility have been verified and the predicted pressure values match well with the measured data.
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Unconventional Geomechanics
More LessSummaryGeomechanics for unconventional reservoirs. Geomechanical properties of the subsurface greatly influence both the drilling and hydraulic fracturing of a well in an unconventional reservoir. A MEM is an estimate of the subsurface mechanical properties, rock strength, pore pressure, and stresses, and can be used to quantify the geomechanical behavior of the subsurface. These components in the MEM are described in this presentation, with an emphasis on applications to developing unconventional reservoirs.
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