Sedimentology from Wellbore to 3-D Reservoir with High-Definition Borehole Images in both Water-Based and Oil-Based Muds
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Recently two near-offset wells were drilled at the Catoosa, Oklahoma USA. The first well was drilled vertically with WBM and logged with an industry-standard high-definition microresistivity imager. The second well was drilled at 25 degrees deviation with OBM and logged with a prototype of a new-generation high-definition OBM-adapted imager. Significant specifications of the new OBM-adapted imager include 192 sensors providing 0.23 in vertical resolution and 98% coverage in 8-in borehole. A quick comparison of the various images acquired validates the quality of the new-generation high-definition OBM-adapted images. The OBM-adapted imager is able to deliver images that are equal to or better than an industry-standard imager run in a WBM environment. The high-definition borehole microresistivity images are increasingly well-established as key input to 3D modelling workflows in clastic reservoirs drilled with water-based fluids (WBM), providing structural and sedimentological control in the near-wellbore space with a much higher degree of confidence than seismic. We focus on demonstrating the use of such images in a workflow for 3D structural and facies modelling. The workflow consists of the several steps to enhance field models based on 3D seismic data, or to produce standalone models that do not depend on the availability of seismic data.Keywords:
Environmental geology
Wellbore
Geophysical Imaging
The Hulusimpang Formation is located in the Bukit Barisan strip and is part of the Woyla terrane associated with Cretaceous volcanic arcs. Research on the Lampung formation, especially the Hulusimpang Formation, is still a little researched. This research was conducted to determine the facies, facies association and depositional environment of the Hulusimpang Formation. The study of facies analysis uses a measured stratigraphic cross section and divides the rock into several facies and facies associations. The facies analysis data was taken from Pekon Way Manak, Sukaagung, Sukamara, Tanggamus Regency. The Hulusimpang Formation consists of seven facies, namely tuff facies (F1), claystone facies (F2), siltstone facies (F3), black siltstone facies (F4), sandstone facies (F5), limestone facies (F6), mudstone facies (F7) . The facies found were grouped into four facies associations, namely channel facies association (AF1) and levee facies association (AF2), creverse splay facies association (AF3), and exposure facies association (AF4). AF1 consists of F1, AF2 consists of F2, F3, F4, F5, AF3 consists of F6, and AF4 consists of F7. Based on the facies association found in the Hulusimpang Formation, it indicates that the depositional environment is Fluvial-Shallow Sea.
Siltstone
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Borehole seismology is the highest resolution geophysical imaging technique available to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This proposal takes direct aim at this shortcoming. P/GSI is developing a 400 level 3C clamped downhole seismic receiver array for borehole seismic 3D imaging. This array will remove the acquisition barrier to record the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore facilitate 9C reservoir imaging. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.
Geophysical Imaging
Vertical seismic profile
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The W formation is the oil measures in Jia oil-gas field.The distribution of oil and gas is controlled by the sedimentary facies. The analysis of log facies plays an important role in the identification of sedimentary facies and the searching for the remaining oil and gas.Depending on the characteristics of log facies,namely campaniform,infundibuliform,box like,dactyloid,linearis,have been identified. Through demarcation of logging facies with core data,and based on the sedimentary microfacies analysis of key well,then the functional relationships between logging facies and sedimentary facies have been established. And then,through the comprehensive analysis of the logging facies of individual wells,the correlation of profiles and the areal study,two kinds of sedimentary facies are recognized,namely delta facies and lacustrine facies.
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We tackle the problem of characterizing the subsurface, more specifically detecting shallow buried objects, using seismic techniques. This problem is commonly encountered in civil engineering when cavities or pipes have to be identified from the surface in urban areas. Our strategy consists of processing not only first arrivals, but also later ones, and using them both in tomography and migration processes, sequentially. These two steps, which form the basis of seismic imaging, can be carried out separately provided that the incident and diffracted wavefields are separated in the data space. Tomography is implemented here as an iterative technique for reconstructing the background velocity field from the first‐arrival traveltimes. The later signals are then migrated by a Kirchhoff method implemented in the space domain. To study the reliability of this methodology, it is first applied to synthetic cases in the acoustic and elastic approximation. Both the background velocity field and the local impedance contrasts are reconstructed as defined in the predicted model. An experimental case, specifically designed for the purpose, is then considered in order to test the algorithms under real conditions. The resulting image coincides well with the predicted model when only P‐waves are generated. In the elastic mode, surface waves make P‐wave extraction difficult, so that the reconstruction remains incomplete. This is confirmed by the real data example. Finally, we demonstrate the appropriateness of the proposed method under such circumstances, provided that suitable preprocessing of data is carried out, in particular, the removal of surface waves.
Geophysical Imaging
Environmental geology
Seismic Tomography
Synthetic data
Seismic migration
Economic geology
Diffraction tomography
Passive seismic
Data Processing
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Imaging through a heterogeneous shallow gas-charged overburden, such as a gas cloud, presents several imaging challenges and is a demanding problem to solve. Our preferred technical solution for imaging beneath gas clouds is to utilize converted wave imaging (Radzi et al., 2015), but this is not always available or cost effective and velocity model building is still difficult. Many previous case studies have been produced from Malaysia which demonstrate subsurface imaging techniques and improvements for fields affected by gas clouds, e.g., Akalin et al. (2010); El Kady et al. (2012); Abd Rahim et al. (2013); Ghazali et al. (2016) and Gudipati et al. (2018). In this paper, we describe a new comprehensive high-density experimental project to readdress these ever-challenging seismic issues by imaging the reservoir from both above and within existing boreholes. The integration of multiple technologies has significantly improved the subsurface images of the field including better-quality velocity models below gas clouds. The new data reveal a larger scale of near-surface heterogeneities than previously expected and future studies will selectively reprocess subsets of the acquired data in order to optimize the images; and, by extension to other similar fields, address a cost-effective imaging strategy.
Overburden
Geophysical Imaging
Gemology
Environmental geology
Economic geology
Geobiology
Igneous petrology
Natural gas field
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G. Gierse, J. Pruessmann, E. Laggiard, C. Boennemann, and H. Meyer show how the Common Reflection Surface (CRS) imaging technique developed by German research and commercial organizations can be successfully applied to a 3D dataset, in this case from a seismic survey off Costa Rica. The macro model independent Common Reflection Surface (CRS) imaging technique has proved to produce superior images in various 2D seismic case studies. A 3D marine dataset application demonstrates similar capabilities of the CRS technique for 3D data. The signal-to-noise ratio is strongly increased and dipping features are better resolved. The marine dataset is selected from the active continental margin offshore Costa Rica. The CRS processing aims at enhancing the image of the slope sediments and deeper crustal structures. The resolution of complex subsurface structures in 2D and 3D still represents a major challenge to seismic exploration. Up to now, continuous efforts have been made throughout the oil and gas industry to improve the imaging of complex structures with the main focus on prestack depth imaging. The seismic wavefront that travels through the complex subsurface is likely to deviate from a spherical shape having passed all sorts of inhomogeneities. Prestack depth migration has the advantage of not assuming a spherical wavefront like conventional techniques, since it calculates the actual deformations of the wavefront from a more or less coarse model of the subsurface. The derivation of the model, however, is a crucial step where prestack depth migration might fail. A very low signal-to-noise ratio in the seismic data often prevents the definition of a reliable basic model and the identification of the main horizons in the prestack data. Likewise, model building can fail in areas of complex tectonics, such as overthrust areas. Thus the strength of the model-based imaging cannot be exploited. For such cases, recent advances in time domain imaging with the CRS technique can be an alternative. CRS processing strongly increases the signal-to-noise ratio, and produces a significant improvement of imaging results. Poststack depth migration allows the transfer of the improved resolution from time domain to depth. In general, time processing has seen fewer efforts to improve the imaging techniques compared with depth processing. In many exploration projects, the conventional NMO / DMO processing flow for producing the zero-offset stack still dominates seismic processing in the time domain. This standard technique has prevailed nearly unchanged throughout the seismic industry during the last two decades. NMO / DMO processing uses a type of a macro model given by the stacking velocity field, which is derived from Common Midpoint (CMP) gathers. The velocity field describes the CMP reflection time curves, which are assumed to be hyperbolic. This assumption corresponds to undisturbed wavefronts from reflection points in a subsurface with plane horizontal layering. In case of dipping layers, the one dimensional subsurface model in the NMO approach leads to reflection point smearing, and requires a partial migration via the Dip Moveout (DMO) correction. Time domain imaging approaches, that were considered alternatives to the established NMO / DMO technique with its simplified subsurface model, have frequently been proposed. At the end of the 80s, de Bazelaire (1986, 1988) and Gelchinsky (1988, 1989) proposed new strategies for a zero-offset imaging. In contrast to the NMO/DMO technique, as well as prestack depth migration, these strategies do not require a macro model, but estimate the imaging parameters directly from the prestack data.
Prestack
Reflection
Geophysical Imaging
Environmental geology
Gemology
Seismic vibrator
Economic geology
Data Processing
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