Modeling dolomitized carbonate‐ramp reservoirs: A case study of the Seminole San Andres unit—Part II, Seismic modeling, reservoir geostatistics, and reservoir simulation

Geophysics ◽  
1998 ◽  
Vol 63 (6) ◽  
pp. 1876-1884 ◽  
Author(s):  
Fred P. Wang ◽  
Jiachun Dai ◽  
Charles Kerans
Keyword(s):  
Reservoir Simulation ◽  
Seismic Data ◽  
High Frequency ◽  
Block Size ◽  
Synthetic Seismograms ◽  
Carbonate Ramp ◽  
High Porosity ◽  
Seismic Modeling ◽  
Rock Fabric ◽  
Seismic Resolution

In part I of this paper, we discussed the rock‐fabric/petrophysical classes for dolomitized carbonate‐ramp rocks, the effects of rock fabric and pore type on petrophysical properties, petrophysical models for analyzing wireline logs, the critical scales for defining geologic framework, and 3-D geologic modeling. Part II focuses on geophysical and engineering characterizations, including seismic modeling, reservoir geostatistics, stochastic modeling, and reservoir simulation. Synthetic seismograms of 30 to 200 Hz were generated to study the level of seismic resolution required to capture the high‐frequency geologic features in dolomitized carbonate‐ramp reservoirs. At frequencies <70 Hz, neither the high‐frequency cycles nor the rock‐fabric units can be identified in seismic data because the tuning thickness of seismic data is much greater than the average thickness of high‐frequency cycles of 6 m. At frequencies >100 Hz, major high‐porosity and dense mudstone units can be better differentiated, while the rock‐fabric units within high‐frequency cycles can be captured at frequencies higher than 200 Hz. Seismic inversion was performed on the 30- to 200-Hz synthetic seismograms to investigate the level of seismic resolution required to recover the high‐resolution inverted impedance logs. When seismic data were noise free, wavelets were known and sampling rates were high; deconvolution techniques yielded perfect inversion results. When the seismic data were noisy, the inverted reflectivity profiles were poor and complicated by numerous high‐frequency spikes, which can be significantly removed using the moving averaging techniques. When wavelets were not known, the predictive deconvolution gave satisfactory inversion results. These results suggest that interwell information required for reservoir characterization can be recovered from low‐frequency seismic data by inversion. Outcrop data were collected to investigate effects of sampling interval and scale‐up of block size on geostatistical parameters. Semivariogram analysis of outcrop data showed that the sill of log permeability decreases and the correlation length increases with an increase of horizontal block size. Permeability models were generated using conventional linear interpolation, stochastic realizations without stratigraphic constraints, and stochastic realizations with stratigraphic constraints. The stratigraphic feature of upward‐shoaling sequences can be modeled in stochastic realizations constrained by the high‐frequency cycles and rock‐fabric flow units. Simulations of a fine‐scale Lawyer Canyon outcrop model were used to study the factors affecting waterflooding performance. Simulation results show that waterflooding performance depends strongly on the geometry and stacking pattern of the rock‐fabric units and on the location of production and injection wells.

Modeling dolomitized carbonate‐ramp reservoirs: A case study of the Seminole San Andres unit—Part I, Petrophysical and geologic characterizations

Geophysics ◽  
1998 ◽  
Vol 63 (6) ◽  
pp. 1866-1875 ◽  
Author(s):  
Fred P. Wang ◽  
F. Jerry Lucia ◽  
Charles Kerans
Keyword(s):  
Reservoir Simulation ◽  
High Frequency ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Total Porosity ◽  
Carbonate Ramp ◽  
Petrophysical Properties ◽  
Rock Fabric ◽  
Wireline Logs ◽  
San Andres

Major issues in characterizing carbonate‐ramp reservoirs include geologic framework, seismic stratigraphy, interwell heterogeneity including rock fabric facies and permeability structure, and factors affecting petrophysical properties and reservoir simulation. The Seminole San Andres unit, Gaines County, West Texas, and the San Andres outcrop of Permian age in the Guadalupe Mountains, New Mexico, were selected for an integrated reservoir characterization to address these issues. The paper is divided into two parts. Part I covers petrophysical and geologic characterization, and part II describes seismic modeling, reservoir geostatistics, stochastic modeling, and reservoir simulation. In dolomitic carbonates, two major pore types are interparticle (includes intergranular and intercrystalline) and vuggy. For nonvuggy carbonates the three important petrophysical/rock fabric classes are (I) grainstone, (II) grain‐dominated packstone and medium crystalline dolostone, and (III) mud‐dominated packstone, wackestone, mudstone, and fine crystalline dolostone. Core data from Seminole showed that rock fabric and pore type have strong positive correlations with absolute and relative permeabilities, residual oil saturation, waterflood recovery, acoustic velocity, and Archie cementation exponent. Petrophysical models were developed to estimate total porosity, separate‐vug porosity, permeability, and Archie cementation exponent from wireline logs to account for effects of rock fabric and separate‐vug porosity. The detailed and regional stratigraphic models were established from outcrop analogs and applied to seismic interpretation and wireline logs and cores. The aggradational seismic character of the San Andres Formation at Seminole is consistent with the cycle stacking pattern within the reservoir. In particular, the frequent preservation of cycle‐based mudstone units in the Seminole San Andres unit is taken to indicate high accommodation associated with greater subsidence rates in this region. A model for the style of high‐frequency cyclicity and the distribution of rock‐fabric facies within cycles was developed using continuous outcrop exposures at Lawyer Canyon. This outcrop model was applied during detailed core descriptions. These, together with detailed analysis of wireline log signatures, allowed construction of the reservoir framework based on genetically and petrophysically significant high‐frequency cycles. Petrophysical properties of total and separate‐vug porosities, permeability, water saturation, and rock fabrics were calculated from wireline log data. High‐frequency cycles and rock‐fabric units are the two critical scales for modeling carbonate‐ramp reservoirs. Descriptions of rock‐fabric facies stacked within high‐frequency cycles provide the most accurate framework for constructing geologic and reservoir models. This is because petrophysical properties can be better grouped by rock fabrics than depositional facies. The permeability‐thickness ratios among these rock fabric units can then be used to approximate fluid flow and recovery efficiency.

scholarly journals Tutorial: Spectral bandwidth extension — Invention versus harmonic extrapolation

Geophysics ◽  
2017 ◽  
Vol 82 (4) ◽  
pp. W1-W16 ◽  
Author(s):  
Chen Liang ◽  
John Castagna ◽  
Ricardo Zavala Torres
Keyword(s):  
Seismic Data ◽  
High Frequency ◽  
Low Frequency ◽  
Original Data ◽  
Spectral Bandwidth ◽  
Bandwidth Extension ◽  
Seismic Resolution ◽  
Earth Structures ◽  
Seismic Sections ◽  
Phase Acceleration

Various postprocessing methods can be applied to seismic data to extend the spectral bandwidth and potentially increase the seismic resolution. Frequency invention techniques, including phase acceleration and loop reconvolution, produce spectrally broadened seismic sections but arbitrarily create high frequencies without a physical basis. Tests in extending the bandwidth of low-frequency synthetics using these methods indicate that the invented frequencies do not tie high-frequency synthetics generated from the same reflectivity series. Furthermore, synthetic wedge models indicate that the invented high-frequency seismic traces do not improve thin-layer resolution. Frequency invention outputs may serve as useful attributes, but they should not be used for quantitative work and do not improve actual resolution. On the other hand, under appropriate circumstances, layer frequency responses can be extrapolated to frequencies outside the band of the original data using spectral periodicities determined from within the original seismic bandwidth. This can be accomplished by harmonic extrapolation. For blocky earth structures, synthetic tests show that such spectral extrapolation can readily double the bandwidth, even in the presence of noise. Wedge models illustrate the resulting resolution improvement. Synthetic tests suggest that the more complicated the earth structure, the less valid the bandwidth extension that harmonic extrapolation can achieve. Tests of the frequency invention methods and harmonic extrapolation on field seismic data demonstrate that (1) the frequency invention methods modify the original seismic band such that the original data cannot be recovered by simple band-pass filtering, whereas harmonic extrapolation can be filtered back to the original band with good fidelity and (2) harmonic extrapolation exhibits acceptable ties between real and synthetic seismic data outside the original seismic band, whereas frequency invention methods have unfavorable well ties in the cases studied.

Integrated Reservoir Characterization Study of a Carbonate Ramp Reservoir: Seminole San Andres Unit, Gaines County, Texas

1998 ◽  
Vol 1 (02) ◽  
pp. 105-113 ◽  
Author(s):  
F.P. Wang ◽  
F. Jerry Lucia ◽  
Charles Kerans
Keyword(s):  
New Mexico ◽  
High Frequency ◽  
Reservoir Characterization ◽  
Scale Up ◽  
Block Size ◽  
Factors Affecting ◽  
Rock Fabric ◽  
Flow Units ◽  
Grid Block ◽  
San Andres

Abstract An integrated reservoir characterization of Seminole San Andres Unit was conducted using outcrop and subsurface data. The high-frequency cycles and rock-fabric facies identified on outcrop and cores were used to correlate wireline logs. Reservoir and simulation models of the outcrop and a two-section area of the Seminole San Andres field were constructed using rock-fabric units within high-frequency cycles (HFC's) as a geologic framework. Simulations were performed using these models to investigate critical factors affecting recovery. High-frequency cycles and rock-fabric units are the two critical scales for modeling shallow-water carbonate ramp reservoirs. Descriptions of rock-fabric facies stacked within high-frequency cycles provide the most accurate framework for constructing geologic and reservoir models because discrete petrophysical functions can be fit to rock fabrics and fluid flow can be approximated by the kh ratios among rock-fabric flow units. Permeability is calculated using rock-fabric-specific transforms between interparticle porosity and permeability. Core analysis data showed that separate-vug porosity has a very strong effect on relative permeability and capillary pressure measurements. The stratigraphic features of carbonates can be observed in stochastic realizations only when they are constrained by rock-fabric flow units. Simulation results from these realizations are similar in recovery but different in production and injection rates. Scale-up of permeability in the vertical direction was investigated in terms of the ratio of vertical permeability to horizontal permeability (kvh). This ratio decreases exponentially with the vertical grid-block size up to the average cycle size of 20 ft (6.1 m) and remains at a value of 0.06 for a grid-block size of more than 20 ft &gt;6.1 m), which is the average thickness of high- frequency cycles. Simulation results showed that critical factors affecting recovery efficiency are stacking patterns of rock-fabric flow units, kvh ratio, and dense mudstone distribution. Introduction More than 9 billion stock-tank barrels of oil has been produced from shallow-water ramp carbonates of the San Andres Formation, West Texas and New Mexico. Because reservoirs in this play are highly heterogeneous and stratified, waterflood recovery averages only 30 percent, and more oil can be recovered if reservoir characterization is done along with infill drilling and CO2 flooding programs. Major issues in characterizing carbonate reservoirs are geologic framework, interwell heterogeneity including rock-fabric facies and permeability structure, scale-up of petrophysical properties, and factors affecting recovery efficiency. Because well spacings in most San Andres fields in West Texas and New Mexico are greater than 600 ft &gt;200 m), outcrops on the Algerita Escarpment in the Guadalupe Mountains, Texas and New Mexico, provide an opportunity to define geologic framework, to quantify interwell heterogeneity, and to develop methods for scale-up of petrophysical properties. Applying the results of outcrop investigations to subsurface reservoirs leads to the development of new methods and techniques for constructing 3-D reservoir and flow models for simulating fluid flow and forecasting performance. The Seminole San Andres Unit (SSAU) lies on the northeastern margin of Central Basin Platform (Fig. 1) immediately south of the San Simon Channel. It covers approximately 23 mi2 and contains more than 600 wells. The field, discovered in 1936, is a solution-gas-drive reservoir with a small initial gas cap and has an estimated original oil in place of 1,100 MMSTB. Production comes from the Upper San Andres Formation and the upper part of the Lower San Andres Formation. The crude is 35 API and has an initial formation volume factor (FVF) of 1.39 and a solution-gas ratio of 684 SCF/STB.

Interpretive advantages of 90°-phase wavelets: Part 2 — Seismic applications

Geophysics ◽  
2005 ◽  
Vol 70 (3) ◽  
pp. C17-C24 ◽  
Author(s):  
Hongliu Zeng ◽  
Milo M. Backus
Keyword(s):  
Seismic Data ◽  
High Frequency ◽  
Seismic Modeling ◽  
Permian Basin ◽  
Seismic Amplitude ◽  
Depositional Systems ◽  
Phase Data ◽  
Dual Polarity ◽  
Gulf Of Mexico Basin ◽  
Zero Phase

We examine field seismic data to test the benefits of 90°-phase wavelets in thin-bed interpretation that are predicted by seismic modeling in part 1 of this paper. In an interbedded sandstone-shale Miocene succession in the Gulf of Mexico basin, a 90°-phase shift of nearly zero-phase seismic data significantly improves lithologic and stratigraphic interpretation. A match between seismic and acoustic impedance (AI) profiles results in a better tie between seismic amplitude traces and lithology-indicative logs. Better geometric imaging of AI units that does not use dual-polarity seismic events results in easier and more accurate reservoir delineation. Less amplitude distortion and the stratigraphy-independent nature of thin-bed interference significantly improves stratigraphic resolution and seismic stratigraphic profiling. For a Ricker-like wavelet having small side lobes, stratigraphic resolution of 90°-phase data is considerably higher than that of zero-phase data. In this specific case, stratigraphic resolution of 90°-phase data is λ/4 (λ = wavelength), compared with λ/2 for its zero-phase counterpart. Stratal slices made from 90°-phase data show geomorphologic patterns of depositional systems with less noise and fewer interference fingerprints. A Permian Basin field provides a real-world example of porous zones in thin, high-frequency carbonate sequences that are better visualized with 90°-phase seismic data than with zero-phase data.

Sparse reflectivity inversion for nonstationary seismic data with surface-related multiples: Numerical and field-data experiments

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. R199-R217 ◽  
Author(s):  
Xintao Chai ◽  
Shangxu Wang ◽  
Genyang Tang
Keyword(s):  
Seismic Data ◽  
Resolution Enhancement ◽  
Synthetic Data ◽  
Data Sets ◽  
Data Set ◽  
Anelastic Attenuation ◽  
Seismic Resolution ◽  
Text Filtering ◽  
The Stability ◽  
Reflectivity Inversion

Seismic data are nonstationary due to subsurface anelastic attenuation and dispersion effects. These effects, also referred to as the earth’s [Formula: see text]-filtering effects, can diminish seismic resolution. We previously developed a method of nonstationary sparse reflectivity inversion (NSRI) for resolution enhancement, which avoids the intrinsic instability associated with inverse [Formula: see text] filtering and generates superior [Formula: see text] compensation results. Applying NSRI to data sets that contain multiples (addressing surface-related multiples only) requires a demultiple preprocessing step because NSRI cannot distinguish primaries from multiples and will treat them as interference convolved with incorrect [Formula: see text] values. However, multiples contain information about subsurface properties. To use information carried by multiples, with the feedback model and NSRI theory, we adapt NSRI to the context of nonstationary seismic data with surface-related multiples. Consequently, not only are the benefits of NSRI (e.g., circumventing the intrinsic instability associated with inverse [Formula: see text] filtering) extended, but also multiples are considered. Our method is limited to be a 1D implementation. Theoretical and numerical analyses verify that given a wavelet, the input [Formula: see text] values primarily affect the inverted reflectivities and exert little effect on the estimated multiples; i.e., multiple estimation need not consider [Formula: see text] filtering effects explicitly. However, there are benefits for NSRI considering multiples. The periodicity and amplitude of the multiples imply the position of the reflectivities and amplitude of the wavelet. Multiples assist in overcoming scaling and shifting ambiguities of conventional problems in which multiples are not considered. Experiments using a 1D algorithm on a synthetic data set, the publicly available Pluto 1.5 data set, and a marine data set support the aforementioned findings and reveal the stability, capabilities, and limitations of the proposed method.

scholarly journals Characterization of reservoir sands using 3D seismic attributes in the coastal swamp area of Niger Delta Basin

2021 ◽  
Author(s):  
Oluwatoyin Khadijat Olaleye ◽  
Pius Adekunle Enikanselu ◽  
Michael Ayuk Ayuk
Keyword(s):  
Seismic Data ◽  
Niger Delta ◽  
Seismic Attributes ◽  
Effective Porosity ◽  
High Porosity ◽  
Hydrocarbon Accumulation ◽  
3D Seismic ◽  
Seismic Attribute ◽  
Niger Delta Basin

AbstractHydrocarbon accumulation and production within the Niger Delta Basin are controlled by varieties of geologic features guided by the depositional environment and tectonic history across the basin. In this study, multiple seismic attribute transforms were applied to three-dimensional (3D) seismic data obtained from “Reigh” Field, Onshore Niger Delta to delineate and characterize geologic features capable of harboring hydrocarbon and identifying hydrocarbon productivity areas within the field. Two (2) sand units were delineated from borehole log data and their corresponding horizons were mapped on seismic data, using appropriate check-shot data of the boreholes. Petrophysical summary of the sand units revealed that the area is characterized by high sand/shale ratio, effective porosity ranged from 16 to 36% and hydrocarbon saturation between 72 and 92%. By extracting attribute maps of coherence, instantaneous frequency, instantaneous amplitude and RMS amplitude, characterization of the sand units in terms of reservoir geomorphological features, facies distribution and hydrocarbon potential was achieved. Seismic attribute results revealed (1) characteristic patterns of varying frequency and amplitude areas, (2) major control of hydrocarbon accumulation being structural, in terms of fault, (3) prospective stratigraphic pinch-out, lenticular thick hydrocarbon sand, mounded sand deposit and barrier bar deposit. Seismic Attributes analysis together with seismic structural interpretation revealed prospective structurally high zones with high sand percentage, moderate thickness and high porosity anomaly at the center of the field. The integration of different seismic attribute transforms and results from the study has improved our understanding of mapped sand units and enhanced the delineation of drillable locations which are not recognized on conventional seismic interpretations.

Seismic resolution enhancement in shale-oil reservoirs

Geophysics ◽  
2018 ◽  
Vol 83 (5) ◽  
pp. B281-B287 ◽  
Author(s):  
Xiwu Liu ◽  
Fengxia Gao ◽  
Yuanyin Zhang ◽  
Ying Rao ◽  
Yanghua Wang
Keyword(s):  
Seismic Data ◽  
Resolution Enhancement ◽  
Oil Reservoirs ◽  
Inversion Method ◽  
Shale Oil ◽  
Data Set ◽  
Extension Method ◽  
Seismic Resolution ◽  
Full Band ◽  
Shale Oil Reservoirs

We developed a case study of seismic resolution enhancement for shale-oil reservoirs in the Q Depression, China, featured by rhythmic bedding. We proposed an innovative method for resolution enhancement, called the full-band extension method. We implemented this method in three consecutive steps: wavelet extraction, filter construction, and data filtering. First, we extracted a constant-phase wavelet from the entire seismic data set. Then, we constructed the full-band extension filter in the frequency domain using the least-squares inversion method. Finally, we applied the band extension filter to the entire seismic data set. We determined that this full-band extension method, with a stretched frequency band from 7–70 to 2–90 Hz, may significantly enhance 3D seismic resolution and distinguish reflection events of rhythmite groups in shale-oil reservoirs.

A 108km2 Compressive Sensing Processing Trial

2021 ◽  
Author(s):  
Dustin Blymyer ◽  
Klaas Koster ◽  
Graeme Warren
Keyword(s):  
Compressive Sensing ◽  
Surface Waves ◽  
Seismic Data ◽  
High Frequency ◽  
Quality Data ◽  
Low Velocity ◽  
Conventional Design ◽  
Seismic Acquisition ◽  
Similar Cost ◽  
Station Density

Abstract Summary Compressive sensing (CS) of seismic data is a new style of seismic acquisition whereby the data are recorded on a pseudorandom grid rather than along densely sampled lines in a conventional design. A CS design with a similar station density will generally yield better quality data at a similar cost compared to a conventional design, whereas a CS design with a lower station density will reduce costs while retaining quality. Previous authors (Mosher, 2014) have shown good results from CS surveys using proprietary methods for the design and processing. In this paper we show results obtained using commercially available services based on published algorithms (Lopez, 2016). This is a necessary requirement for adoption of CS by our industry. This report documents the results of a 108km2 CS acquisition and processing trial. The acquisition and processing were specifically designed to establish whether CS can be used for suppression of backscattered, low velocity, high frequency surface waves. We demonstrate that CS data can be reconstructed by a commercial contractor and that the suppression of backscattered surface waves is improved by using CS receiver gathers reconstructed to a dense shot grid. We also show that CS acquisition is a reliable alternative to conventional acquisition from which high-quality subsurface images can be formed.

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