Borehole images play a crucial role in tight gas exploration. Recognition of sedimentary features helps in understanding the depositional architecture and allows refinement of the facies model for flow unit identification and stimulation treatment. The structural analysis of faults and fractures provides clues not only about the tectonic history, but also about the possible conduits for fluid migration that lead to diagenesis. The diagenetic imprints and their impact in a sequence stratigraphic framework can be understood through textural analysis performed on the borehole images across the field. And, hydro- fracturing of tight gas reservoirs require important input from the borehole images in understanding the variability of stress regimes. Established micro-resistivity imagers for the water-base mud (WBM) environment provide robust results, except when there is a large contrast between the formation resistivity (Rt) and the mud resistivity (Rm). With more frequent use of hyper-saline mud, a new and improved definition imager is deployed to obtain high quality images. Novel hardware and improved signal processing algorithms are employed to acquire the images despite the hostile conditions provided by the combination of low- resistivity salt-saturated (WBM) and high formation resistivity that would otherwise impede the data quality. Early field testing of this enhanced capability took place in the Sultanate of Oman and the examples of its improved performance are presented. Getting the most detailed image data in oil-base mud (OBM) is challenging compared to the WBM systems. As an alternative to the options commercially available in the industry today, the new high-definition imager developed for the WBM system can also be used under favorable conditions to acquire valid images in the OBM. The high-definition imager works best in OBM when both formation resistivity and mud permittivity are high. A workflow is developed for the Go – No Go decisions for borehole imaging tools in different mud systems for tight gas reservoirs. It is important at the planning phase of the logging programs to anticipate the imaging tool behavior in the proposed mud system and conditions. The results from trials made in the tight gas reservoirs of North Oman provided the basis for a decision tree for imaging, since the logging environment exerts a strong control on data quality. The decision-tree presented here aims to ensure that images acquired are the most suitable for detailed geologic interpretation and subsequent integration in development plans for optimal exploitation of tight gas sands in Oman.
Nuclear magnetic resonance (NMR) data acquisition and interpretation in carbonate reservoirs is much more challenging than in sandstones, where it is a well-established technology. Heterogeneous porosity distribution, a broad range of pore sizes, a wide variety of complex textures, and low surface relaxivity combine to complicate the picture considerably. The successful practical application of NMR in these reservoirs requires the development of acquisition and interpretation techniques specifically suited to the task. In carbonate reservoirs dominated by intercrystalline or intergranular porosity, NMR can deliver accurate estimates of porosity, permeability, bound-fluid volume, and residual oil saturation. In vuggy, heterogeneous carbonates more complex interpretation models, based on the integration of whole-core and log data, are required for reliable answers. NMR answer products, based on these new techniques, are presented and validated with core data and by comparison to other logs. Introduction In many clastic reservoirs the CMR Combinable Magnetic Resonance tool has proven its ability to easily and accurately provide a number of answers not possible with conventional logging tools. From a single measurement of signal amplitude and transverse relaxation time (T2), it is possible to determine porosity, permeability, and bound- and free-fluid volumes and to estimate residual oil volumes. Extending this success to the carbonate reservoirs of West Texas is the focus of this study. CMR interpretation in these formations is not always straightforward and normal acquisition parameters are not necessarily sufficient to produce data relevant to the task at hand. For instance, under normal reservoir conditions, the oil signal and the water signal cannot be differentiated in most carbonates. Also, permeability estimated using the same simple treatment given to sandstones does not always match up well with core permeability. Despite these hurdles, quality answers are still attainable. The CMR* tools' accurate lithology-independent porosity is often critical in these complex carbonate reservoirs. Correct bound-fluid volumes are easily obtained using the right cutoff. Good permeability estimates are possible in carbonates, although this may initially require calibration versus core data and other logs in each field. And finally, a simple mud- doping procedure will allow the correct determination of residual oil saturation (ROS). NMR Petrophysics of Carbonates Petrophysically speaking, the most obvious difference between carbonates and sands lies in the heterogeneity of porosity distribution. In general, carbonates can be said to possess a wider range of pore sizes and geometries than sandstones, which are homogeneous and predictable by comparison. This gives rise to a number of physical properties in carbonates that directly affect NMR measurements. First, there are the properties that affect the T1 and T2 distributions of the formation. Because a wider range of pore sizes occurs in carbonates, the T2 distribution will generally be more dispersed than in sands. The largest of these pores will result in very long relaxation times; we show that this directly impacts logging speed and interferes with residual oil measurement. Additionally, an inherent matrix property of carbonates, low surface relaxivity, makes for longer relaxation times (Timur, 1972). Sandstone reservoirs consistently contain about 1% iron by weight. This results in a surface relaxivity of about 15 microns/s. By contrast, a typical carbonate matrix contains less impurities and has surface relaxivity in the range of 5 microns/s (Chang et al, 1994). P. 217^
With the increase in activity in deep and ultra-deep water exploration, the need for geological information is penalized by its cost. Acquiring full core data in the current economic context is difficult to justify and encourages the development of less costly alternative methodologies to compensate the lack of information when coring is not included in exploration programs. This is particularly true in oil- or synthetic-base muds (OBM) where such alternative technology is still under development as opposed to the water-base mud (WBM) environment where the technology is more mature and the interpretation workflows are better established. New state-of-the-art electric wireline technologies including large-volume rotary sidewall coring, and photorealistic OBM-adapted formation imaging combined with powerful software tools for visualization and interpretation are demonstrated to provide a viable substitute for whole conventional core for a wide range of applications, especially in clastic environments.
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