We evaluated an advanced forward-modeling-based reservoir characterization technique that uses full elastic finite-difference simulation to investigate the limits of karst identification in stacked seismic data. Identification of karsts is important for field development in carbonated reservoirs because paleokarst features can result in a loss of circulation and/or sometimes lost drill bits. Our primary objective was to verify whether we can detect and interpret the location and size of karsts from seismic data, especially given a complex overburden. We constructed an elastic reservoir model consisting of compressional velocity ([Formula: see text]), shear velocity ([Formula: see text]), and density for the study area using interpreted horizons and well log information. Karsts with varying widths, thicknesses, dip angles, and porosities were inserted to generate multiple versions of the model. We also evaluated the imaging impact of overlying faults and salt on karst detection. Full elastic simulation was performed on the various reservoir models using a realistic acquisition geometry to generate gathers, which were then prestack time migrated to quantify the impact of different karst properties on the seismic images and study the effect of reservoir property changes on the seismic response. Finally, a wave-equation target-oriented analysis was presented to improve the understanding of subsalt amplitude and illumination. From the finite-difference modeling and analysis that we performed, we obtained an uncertainty range on karst property estimation from seismic images and gained insights into future survey design for subsalt interpretation and amplitude analysis. For our specific model, we found the limit of karst identification from seismic data is a 30-m-wide horizontal karst or a 500 m karst dipping at 60°. Also, the karst image width reflected its true width only when the actual karst width was larger than the P-wave wavelength (240 m in this case). With a dipping overburden above the reservoir, apparent positions of karsts were shifted in the updip direction by prestack time migration up to 50 m from their true position. This lateral uncertainty should be kept in mind in well planning to avoid karst features interpreted from a time-migrated seismic section.

Unconventional resources such as shale gas are becoming increasingly important exploration, development, and production targets. However, geophysical characterization of these unconventional reservoirs remains challenging because of limited understanding of geophysical responses to reservoir properties such as total organic carbon (TOC). We have developed an improved anisotropic rock-physics model to incorporate TOC effects, in addition to effects of mineralogy, porosity, and fluid content, on seismic and electrical properties of shale gas. The modeling results suggest that an increase in the organic content generally reduces P-impedance, and Vp/Vs ratio, while increasing the velocity anisotropy and resistivity. This general trend is further modified by mineralogical compositions.

Abstract This paper provides a new computational rock physics study of middle east carbonate rock. Computed elastic and electrical properties from real rock micro-tomographis and constructed 3D sphere packs build direct link between rock microstructure and its elastic, electrical responses. Multi-resolution CT scans (resolution varying from nanometer to micron) are taken for carbonate core samples belonging to different facies from middle east carbonate reservoirs. Different carbonate petrophysical pore types shows clearly different pore structures (pore shape, size, connectivity). Laplace equation and linear Stokes equation are directly solved on those 3D rock micro-tomographis to compute electrical conductivity and hydraulic permeability using finite difference method (FD). Elastic properties (Vp, Vs, bulk modulus, shear modulus, Young's modulus and Poisson's Ratio) are computed by solving linear stress-strain relationship using finite element method (FEM). To further extend predicting capability, a family of 3D model granular porous media with different porosity, pore (grain) aspect ratio, pore (grain) size distribution, pore connectivity and spatial arrangement are built to represent different carbonate petrophysical pore types. Results for different carbonate facies (Wackestone with roundish micropore system (microporosity); Grainstone, Packstone with interpartical pore (IP) system; Rudstone with vuggy porosity and IP frame) are shown. Measurements on core plugs compare well with modeling results and computed values. We can rigorously determine the pore geometry related parameters in effective medium based model (Xu-Payne model) from numerical computation to interpret and predict log response for upscaling. Finally, AVO seismic forward modeling is built to quantify porosity, fluid saturation and lithology (facies) effect on seismic response for middle east carbonate reservoir. A complete study at pore and core scale, log scale to seismic scale is achieved. Conclusions and recommendations on inverting porosity, fluid saturation and carbonate facies from pre-stack seismic in carbonate reservoir are given at the end.

Geophysical characterization of organic-rich shales involves remote estimation of the geological and geomechanical properties. Important geological properties are porosity, clay content (Vclay), and the total organic carbon (TOC). Important geomechanical properties are natural fractures and fracability (ease of hydraulically fracturing the rock). Apart from various engineering factors, the fracability depends on the following geological factors: in-situ stress (the vertical effective stress and the minimum and maximum horizontal effective stresses), pore pressure, brittleness, and rock strength. At well locations, we sometimes have the luxury of having enough measurements to completely characterize the shale properties of interest. However, we do not normally have enough measurements away from wells, and as a result the estimation of rock properties remains under-determined. On the other hand, the seismic measurements typically can be used to provide an estimate of the acoustic impedance (AI) and Vp/Vs ratio of the rock. Occasionally we may estimate density if seismic data have sufficient quality and enough offset coverage, and the anisotropic elastic properties with varying degrees of measurement errors. Due to the complexity of shale reservoirs, the relatively large number of rock properties, and the limited amount of independent information that we can measure at the field, the inversion for the rock properties often remains nonunique.

Abstract A recent reprocessing of a large Ocean Bottom Cable (OBC) seismic data set of a Giant Offshore Carbonate Oilfield in U.A.E. resulted in significant seismic imaging, signal/noise ratio, and detectability improvements of faults and horizon geometries which included new fault system sets never recognized before. In addition, seismic amplitude fidelity was improved significantly and it has been confirmed by well-to-seismic ties, acoustic impedance inversion, and quantitative attribute analysis. This paper will mainly focus on the results of the acoustic impedance inversion and porosity prediction by seismic attribute analysis and applications to field development. Hundreds of regular wire-line and/or cross-dipole sonic logs were acquired and dozens of ultrasonic measurements from core samples were performed across the field. Data was conditioned and analyzed to understand the porosity versus impedance and other rock physics trends. A relatively narrow porosity versus impedance trend was observed in the data set, which laid the foundation for our subsequent analysis. Acoustic impedance inversion were performed by 1) well-to-seismic tie and wavelet estimation, 2) earth model building based on interpretation and well data, 3) band-limited impedance inversion and total impedance derivation. The inversion results and seismic stacks were loaded into a seismic attribute analysis package where multi attribute analysis was performed and porosity versus impedance and other attribute relationship was established. The porosity volume was then generated across the entire field based on the established relationship. The resulted porosity volume based on the inversion results and other attributes and extracted maps from these volumes for different intervals were validated with well data where high consistency was observed. Since these volumes are layered properties not interface based reflectivity data like stack seismic, they can be directly correlated to geologic layers such as lithological unit etc. therefore they make the integration of geological and engineering data much easier. The volumes show higher resolution than regular stack seismic data and examples will be shown how this data has been used for thinner reservoir mapping, well planning, and input for geological models.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2010Seismic constrained reservoir property prediction — example from a Middle East carbonate field Offshore Abu Dhabi, UAEAuthors: Jie ZhangRaed El‐AwawdehZyg J. ShevchekNaeema KhouriAkmal SultanChristopher E. HarrisJoe M. ReillyJie ZhangZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, Raed El‐AwawdehZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, Zyg J. ShevchekZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, Naeema KhouriZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, Akmal SultanZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, Christopher E. HarrisZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this author, and Joe M. ReillyZakum Development CompanyExxonMobil Upstream Research CompanySearch for more papers by this authorhttps://doi.org/10.1190/1.3513084 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract A recent reprocessing of a large Ocean Bottom Cable (OBC) seismic data set of a Middle East Offshore Carbonate Oilfield in U.A.E. resulted in significant seismic imaging, signal/noise ratio, and detectability improvements of faults and horizon geometries which included new fault system sets never recognized before. In addition, seismic amplitude fidelity was improved significantly and it has been confirmed by better well‐ties and subsequent acoustic impedance inversion, which enabled seismic quantitative analysis possible. This paper will focus on the description of a successful application of porosity prediction based on the data and a workflow that consists of four major steps: rock property analysis, acoustic impedance inversion, porosity prediction from multi‐attribute analysis, and validation based on well data. Hundreds of regular wire‐line and/or cross dipole sonic logs were acquired and dozens of ultrasonic measurements from core samples were performed across the field. Data was conditioned and analyzed to understand the porosity versus impedance and other rock physics trends. A relatively narrow porosity versus impedance trend was observed in the data set, which laid the foundation for our subsequent analysis. Acoustic impedance inversions were performed in a commercial software package by 1) well‐to‐seismic tie and wavelet estimation, 2) earth model building based on interpretation and well data, 3) band‐limited impedance inversion and total impedance derivation. The inversion results and seismic stacks were loaded into a seismic attribute analysis software package where seismic multi‐attribute analysis was performed and porosity versus impedance and other attribute relationship was established. The porosity volume was then generated across the entire field based on the established relationships. The resulted porosity volumes based on the inversion results and other attributes were validated with well data where high consistency was observed. These volumes are layered properties rather than reflectivity tied to interfaces; therefore they can be very easily used for integration between geological and engineering data. Also higher frequency was observed within the volumes. Examples of application of the impedance and porosity volumes for thinner reservoir mapping, well planning, and input for geological models will be shown.Permalink: https://doi.org/10.1190/1.3513084FiguresReferencesRelatedDetailsCited ByFracture characterization from seismic attributes and anisotropy through core and image log integration in a giant offshore oil fieldAkmal A. Sultan, Mohammed Y. Ali, Youcef Bouzidi, Eric M. Takam Takougang, Fateh Bouchaala, and Aala A.I. Mohamed27 August 2018Role of high quality seismic data in field development and production through case studies from a giant offshore carbonate field, Abu Dhabi, UAEAkmal Sultan, Jie Zhang, H. Ewart. Edward, S. Ahmed Hage, Khaled Shahata, and Kamran Jan25 May 2012 SEG Technical Program Expanded Abstracts 2010ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2010 Pages: 4453 publication data© 2010 Copyright © 2010 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished: 21 Oct 2010 CITATION INFORMATION Jie Zhang, Raed El‐Awawdeh, Zyg J. Shevchek, Naeema Khouri, Akmal Sultan, Christopher E. Harris, and Joe M. Reilly, (2010), "Seismic constrained reservoir property prediction — example from a Middle East carbonate field Offshore Abu Dhabi, UAE," SEG Technical Program Expanded Abstracts : 1312-1316. https://doi.org/10.1190/1.3513084 Plain-Language Summary PDF DownloadLoading ...

Unconventional resources such as shale gas are becoming increasingly important exploration and production targets. To understand the geophysical responses of shale-gas plays, we use a rock physics relationship, which is constrained with geology and formation-evaluation analysis, to calculate effective properties such as impedance and [Formula: see text]. Numerical studies suggest that in-situ rock para-meters such as mineral composition (e.g., clay, quartz, and calcite) and TOC, as well as the interaction among them, can significantly influence the geophysical responses of the organic-rich rocks, thus providing the basis for the geophysical characterization of shale-gas plays.

Abstract Outcrop and marine field work on the NW part of the Caicos platform illustrates Pleistocene-Holocene accretion of the Providenciales and West Caicos Islands, the effects of the Holocene transgression on the flooded substrate, and the differentiation of sedimentary provinces in relation to prevailing current direction and inherited topography. A marine field study of 2D seismic (CHIRP) sub-bottom profile data and surface sediment sampling on the shelf north of Providenciales and North Caicos, and on the platform interior south of Providenciales provide an image of the top-Pleistocene surface, the thickness of Holocene sediments, and the present distribution of facies, biogenic components, and grain sizes. A pronounced difference in the composition and grain sizes of Holocene sediments exists between the open shelf north and the platform interior south of Providenciales, but maximum thicknesses of approximately 2 meters are similar. On the back-reef shelf, peloidal nearshore sands grade seaward to coarse skeletal sands, rocky bottoms and reefs. On the platform interior, the sediments are peloidal and skeletal on or near beaches, coarse skeletal grains and rubble near patch reefs, and peloidal grainstones and mud-lean packstones elsewhere in the subtidal environment. Outcrop mapping and Uranium-Thorium age dating of carbonate material from Providenciales and West Caicos provide constraints on island growth and sequence development during the Pleistocene and Holocene. Providenciales has two discontinuous core ridges of eolian and subtidal deposits with ages ranging between 160 and 302 Ka. Cutting the island core and prograding away from it are shingles (up to 4 parasequences) of marine and eolian sediments deposited during 140-90 Ka representing the transgression and high stand of isotopic stages 5e and c. Comparison of the elevation of Pleistocene marine deposits (> 12 m) and published sea level curves for the area indicates the need for uplift or higher sea levels for the island. Holocene eolian ridges, beaches, and strandplains form a discontinuous outer shingle on the island. West Caicos is cored by two eolian cores with similar age sediments (219-136 Ka), followed by reef and beach growth (120-130 ka) and younger Holocene eolian ridges making up the east and northeast extension of the island.

New seismic data reprocessing has improved seismic interpretations for a major Middle East offshore oil field. Significant new fault patterns have been identified within a Kharaib carbonate reservoir using multiple seismic volumes. These were generated from post-stack reprocessing of a full-field 1,500 square km data volume and full reprocessing from field tape of a crestal 200 square km data set. The new fault framework will be incorporated into geologic models for simulation modeling that will help drive the development plan for the field. The full-field post-stack reprocessing flow was designed to reduce noise, thereby enhancing stratigraphic detail and fault definition. Near-, mid-, far-, and full-stacks, spectral whitening and spectral decomposed data show different degrees of resolution. The full reprocessing from field tape used a processing flow that was specifically designed to address severe water-bottom energy surface noise and variable short-period reverberatory multiples. It used separate processing flows for hydrophone and geophone data. Noise reduction from the reprocessing allowed consistent and efficient automated horizon picking. The interpretation approach included the generation of new horizons and a disciplined approach to fault identification using multiple volumes and attributes. From the new data, automated horizons were picked, which led to better identification of small faults using horizon-based attributes. The new data allowed us to identify pervasive NE-SW and N-S faults in parts of the field and to subdivide major faults into smaller faults at different stratigraphic levels. These encouraging results motivated us to plan full-field full reprocessing from field tape.