scholarly journals Facies models of hydrocarbon-bearing formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields

2021 ◽  
Vol 6 (4) ◽  
pp. 43-53
Author(s):  
Oksana A. Popova ◽  
Oleg O. Uraev
Keyword(s):  
Seismic Data ◽  
Development Planning ◽  
Seismic Survey ◽  
Target Interval ◽  
Tidal Channels ◽  
Reservoir Properties ◽  
The Core ◽  
Reservoir Architecture ◽  
Geological Features ◽  
Quantitative Characteristics

Background. Significant part of hydrocarbons at Bovanenkovskoye and Kharasaveyskoye fields are contained in Podneytinskiy reservoir, and study of geological features of its productive strata is important for development planning for the fields in a whole. Aim. The paper reflects the results of integrating well and seismic data to characterize the formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields. Materials and methods. As part of the study, sedimentological description of core was analyzed, the core, well logging and seismic survey information were assessed, and the facies schemes were prepared. Results. As a result of the work, the reservoir architecture features and the distribution of reservoir properties of the target interval were revealed. It has been established that the considered formations of Podneytinskiy reservoir can be divided into two parts, the lower one is represented by deposits of predominantly deltaic origin, and the upper one is of continental and subcontinental genesis. The sedimentary conditions of rocks influenced the complexity of their architecture, so, in the formations referred to the lower part of the studied interval, the reservoirs, as a rule, are laterally continuous, in contrast to the deposits of the upper part of the section, which are typically characterized by extremely high lateral heterogeneity. Depositional conditions also influenced the reservoir properties of productive sediments. As a result of the work, it was revealed that the reservoirs of better quality are formed in fluvial and tidal channels, distributary channels and proximal parts of deltas, they have higher reservoir properties, are characterized by thicker sandstone interlayers and lower portion of carbonated interlayers in comparison with reservoirs formed in other conditions. Conclusions. The article provides quantitative characteristics of reservoir properties depending on sedimentary conditions. The results obtained form the basis for creation of geological models of Bovanenkovskoye and Kharasaveyskoye fields.

scholarly journals Instantaneous Attributes Applied to Full Waveform Sonic Log and Seismic Data in Integration of Elastic Properties of Shale Gas Formations in Poland

2018 ◽  
Vol 35 ◽  
pp. 03007 ◽  
Author(s):  
Kamila Wawrzyniak-Guz
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Seismic Survey ◽  
Reservoir Properties ◽  
Full Waveform ◽  
Rock Formations ◽  
Sonic Log ◽  
Geological Factors ◽  
Full Waveforms ◽  
Frequency Phase

Seismic attributes calculated from full waveform sonic log were proposed as a method that may enhance the interpretation the data acquired at log and seismic scales. Though attributes calculated in the study were the mathematical transformations of amplitude, frequency, phase or time of the acoustic full waveforms and seismic traces, they could be related to the geological factors and/or petrophysical properties of rock formations. Attributes calculated from acoustic full waveforms were combined with selected attributes obtained for seismic traces recorded in the vicinity of the borehole and with petrophysical parameters. Such relations may be helpful in elastic and reservoir properties estimation over the area covered by the seismic survey.

scholarly journals Estimation of reservoir properties from seismic data by smooth neural networks

Geophysics ◽  
2003 ◽  
Vol 68 (6) ◽  
pp. 1969-1983 ◽  
Author(s):  
M. M. Saggaf ◽  
M. Nafi Toksöz ◽  
H. M. Mustafa
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Back Propagation ◽  
Reservoir Rock ◽  
Seismic Survey ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Network Parameters ◽  
Generalization Problem ◽  
Validation Tests

The performance of traditional back‐propagation networks for reservoir characterization in production settings has been inconsistent due to their nonmonotonous generalization, which necessitates extensive tweaking of their parameters in order to achieve satisfactory results and avoid overfitting the data. This makes the accuracy of these networks sensitive to the selection of the network parameters. We present an approach to estimate the reservoir rock properties from seismic data through the use of regularized back propagation networks that have inherent smoothness characteristics. This approach alleviates the nonmonotonous generalization problem associated with traditional networks and helps to avoid overfitting the data. We apply the approach to a 3D seismic survey in the Shedgum area of Ghawar field, Saudi Arabia, to estimate the reservoir porosity distribution of the Arab‐D zone, and we contrast the accuracy of our approach with that of traditional back‐propagation networks through cross‐validation tests. The results of these tests indicate that the accuracy of our approach remains consistent as the network parameters are varied, whereas that of the traditional network deteriorates as soon as deviations from the optimal parameters occur. The approach we present thus leads to more robust estimates of the reservoir properties and requires little or no tweaking of the network parameters to achieve optimal results.

Interpretation of geologic facies in seismic volume using key rock elastic properties and high-definition facies templates

2017 ◽  
Vol 5 (2) ◽  
pp. SE11-SE27 ◽  
Author(s):  
Mahbub Alam ◽  
Sabita Makoon-Singh ◽  
Joan Embleton ◽  
David Gray ◽  
Larry Lines
Keyword(s):  
Elastic Properties ◽  
Oil Recovery ◽  
Seismic Data ◽  
Effective Porosity ◽  
Rock Properties ◽  
Small Scale ◽  
High Definition ◽  
Reservoir Properties ◽  
Particle Volume ◽  
Reservoir Architecture

We have developed a deterministic workflow in mapping the small-scale (centimeter level) subseismic geologic facies and reservoir properties from conventional poststack seismic data. The workflow integrated multiscale (micrometer to kilometer level) data to estimate rock properties such as porosity, permeability, and grain size from the core data; effective porosity, resistivity, and fluid saturations using petrophysical analyses from the log data; and rock elastic properties from the log and poststack seismic data. Rock properties, such as incompressibility (lambda), rigidity (mu), and density (rho) are linked to the fine-particle-volume (FPV) ranges of different facies templates. High-definition facies templates were used in building the high-resolution (centimeter level) near-wellbore images. Facies distribution and reservoir properties between the wells were extracted and mapped from the FPV data volume built from the poststack seismic volume. Our study focused on the heavy oil-bearing Cretaceous McMurray Formation in northern Alberta. The internal reservoir architecture, such as the stacked channel bars, inclined heterolithic strata, and shale plugs, is intricate due to reservoir heterogeneity. Drilling success or optimum oil recovery will depend on whether the reservoir model accurately describes this heterogeneity. Thus, it is very important to properly identify the distribution of the permeability barriers and shale plugs in the reservoir zone. Dense vertical well control and dozens of horizontal well pairs over the area of investigation confirm a very good correlation of the geologic facies interpreted between the wells from the seismic volume.

Quantitative thickness estimates from the spectral response of AVO measurements

Geophysics ◽  
2008 ◽  
Vol 73 (1) ◽  
pp. C1-C6 ◽  
Author(s):  
Ethan J. Nowak ◽  
Herbert W. Swan ◽  
Dave Lane
Keyword(s):  
Frequency Band ◽  
Seismic Data ◽  
Spectral Decomposition ◽  
Spectral Response ◽  
Seismic Survey ◽  
Decomposition Technique ◽  
Target Interval ◽  
Optimization Scheme ◽  
Resolution Limits ◽  
Marine Seismic

This study is motivated by the necessity to quantitatively characterize subtuned reservoirs. The conventional autocorrelation-based spectral-decomposition technique uses frequency notches to calculate vertical traveltime thickness of a layer of dipole reflectivity. Those notches tend to move outside the usable frequency band of the seismic data as the layer exceeds the tuning threshold of the wavelet. Assuming wavelet stationarity and nondipole reflectivity, a similar analysis performed on a crosscorrelation between an intercept and gradient trace extends the resolution limits to one-half the tuning threshold. That is a major improvement; however, many economic reservoirs still do not meet the half-tuning requirement. Such thin reservoirs led to the development of an optimization scheme. This approach, which does not require any wavelet stationarity or reflectivity assumptions, theoretically is not limited by the thickness of the target interval. The optimization scheme was applied successfully to a marine seismic survey in an attempt to estimate the traveltime thickness of a chalk reservoir.

Integrated shale-gas reservoir characterization: A case study incorporating multicomponent seismic data

2018 ◽  
Vol 6 (2) ◽  
pp. SE23-SE37
Author(s):  
Laurie M. Weston Bellman
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Data Interpretation ◽  
Seismic Profile ◽  
Gas Production ◽  
Seismic Survey ◽  
Reservoir Properties ◽  
Converted Wave ◽  
Multistage Hydraulic Fracturing

The objective of this case study is to predict geologic properties of a shale reservoir interval to guide production and completion planning for successful development of the reservoir. The conditioning, analysis, and blending of the converted-wave (PS) seismic data into a quantitative interpretation (QI) workflow are described in detail, illustrating the successful integration of geologic information and multiple seismic attributes. A multicomponent 3D seismic survey, several wells with dipole sonic logs, and a multicomponent (3C) 3D vertical seismic profile are available for the study. For comparisons of the incremental value of PS data, the QI workflow is completed entirely using only PP data and then modified and redone to incorporate information from the PS data. Predictions of the geologic properties for both workflows are assessed for accuracy against the existing well log and core evidence. Determining reservoir properties of the shale units of interest is important to the successful placement of horizontal wells for efficient multistage hydraulic fracturing and maximum gas production. Although conventional interpretation of conventional seismic data can only provide reservoir geometry, the quantitative analysis of prestack multicomponent data in this study reveals detailed distinctions between reservoir units and relative measures of porosity and brittleness bulk properties within each unit. Using all of the elastic properties derived from the seismic data analysis allowed for the classification of lithological units, which were, in turn, subclassified based on unit-specific reservoir properties. The upper reservoir units (Muskwa and Otter Park) were shown to have more variability in brittleness than the lower reservoir unit (Evie). Validation at a reliable well control confirmed these distinctive units and properties to be very high resolution and accurate, particularly when the PS data were incorporated into the workflow. The results of this method of analysis provided significantly more useful information for appraisal and development decisions than conventional seismic data interpretation alone.

Multidisciplinary Analysis of Hydraulic Stimulation and Production Effects within the Niobrara and Codell Reservoirs, Wattenberg Field, Colorado: Part 1 - Baseline Reservoir Conditions

2021 ◽  
pp. 1-41
Author(s):  
Matthew Bray ◽  
Jacquelyn Daves ◽  
Daniel Brugioni ◽  
Asm Kamruzzaman ◽  
Tom Bratton ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Time Lapse ◽  
Organic Content ◽  
P Wave ◽  
Seismic Survey ◽  
Fracture Density ◽  
Niobrara Formation ◽  
Reservoir Properties ◽  
Wattenberg Field

In the Wattenberg Field, the Reservoir Characterization Project at the Colorado School of Mines and Occidental Petroleum Corporation (Oxy) (formerly the Anadarko Petroleum Corporation) collected time-lapse seismic data for characterization of changes in the reservoir caused by hydraulic fracturing and production in the Niobrara Formation and Codell Sandstone member of the Carlile Formation. We have acquired three multicomponent seismic surveys to understand the dynamic reservoir changes caused by hydraulic fracturing and production of 11 horizontal wells within a 1 mi2 section (the Wishbone Section). The time-lapse seismic survey acquisition occurred immediately after the wells were drilled, another survey after stimulation, and a third survey after two years of production. In addition, we integrate core, petrophysical properties, fault and fracture characteristics, as well as P-wave seismic data to illustrate reservoir properties prior to simulation and production. Core analysis indicates extensive amounts of bioturbation in zones of high total organic content (TOC). Petrophysical analysis of logs and core samples indicates that chalk intervals have high amounts of TOC (>2%) and the lowest amount of clay in the reservoir interval. Core petrophysical characterization included X-ray diffraction analysis, mercury intrusion capillary pressure, N2 gas adsorption, and field emission scanning electron microscopy. Reservoir fractures follow four regional orientations, and chalk facies contain higher fracture density than marl facies. Integration of these data assist in enhanced well targeting and reservoir simulation.

scholarly journals Estimation of Shallow Sulphur Deposit Resources Based on Reflection Seismic Studies and Well Logging

Energies ◽  
2021 ◽  
Vol 14 (17) ◽  
pp. 5323
Author(s):  
Kamil Cichostępski ◽  
Jerzy Dec
Keyword(s):  
Cross Section ◽  
Seismic Data ◽  
Seismic Signal ◽  
Well Logging ◽  
Seismic Survey ◽  
Borehole Data ◽  
Reservoir Properties ◽  
Reflection Seismic ◽  
Se Poland ◽  
Novel Method

In this article we present a novel method for the estimation of sulphur deposit resources based on high-resolution shallow reflection seismic survey and well logging. The study area was sited in the northern part of the Carpathian Foredeep (SE Poland), where sulphur ore occurs in carbonate rocks at a depth of about 120 m, with a thickness of approximately 25 m. The results of many years of seismic monitoring performed in the area of the sulphur deposit allowed us to determine the quantitative relationships between the amplitude of the seismic signal reflected from the top of the deposit and its petrophysical parameters such as porosity and sulphur content. The method of evaluating sulphur deposit is based on extensive statistics concerning the reservoir properties obtained from borehole data. We also discuss a methodology for conducting field acquisition and processing of seismic data in the aspect of mapping the actual amplitudes of the signal reflected from the top of a deposit. The results of estimating the abundance of carbonate sulphur deposits are presented based on the example of a seismic cross-section from the Osiek sulphur mine. Obtained results allow indicating the most prospective zones suitable for exploitation.

COMPOSITION AND RESERVOIR PROPERTIES OF DEPOSITS OF THE BAZHENOV FORMATION IN THE CENTRAL PART OF TUNDRIN DEPRESSION

2018 ◽  
pp. 107-111
Author(s):  
O. M. Makarova ◽  
N. I. Korobova ◽  
A. G. Kalmykov ◽  
G. A. Kalmykov
Keyword(s):  
Reservoir Properties ◽  
Bazhenov Formation ◽  
The Core ◽  
Petrophysical Data ◽  
Pore Types

According to lithological and petrophysical data the core of the Bazhenov Formation, discovered in the central part of the Tundrin Basin, the structure of the section was characterized , productive oil intervals were identified, in which the collectors of pore and fissure-pore types are developed.

Effects of incomplete parameterization on full-wavefield viscoelastic seismic data for petrophysical reservoir properties

Geophysics ◽  
2007 ◽  
Vol 72 (3) ◽  
pp. O9-O17 ◽  
Author(s):  
Upendra K. Tiwari ◽  
George A. McMechan
Keyword(s):  
Seismic Data ◽  
Input Data ◽  
Elastic Model ◽  
Quality Factors ◽  
Noise Levels ◽  
Reservoir Properties ◽  
Estimated Parameters ◽  
Model Parameterization ◽  
The Earth ◽  
Incomplete Model

In inversion of viscoelastic full-wavefield seismic data, the choice of model parameterization influences the uncertainties and biases in estimating seismic and petrophysical parameters. Using an incomplete model parameterization results in solutions in which the effects of missing parameters are attributed erroneously to the parameters that are included. Incompleteness in this context means assuming the earth is elastic rather than viscoelastic. The inclusion of compressional and shear-wave quality factors [Formula: see text] and [Formula: see text] in inversion gives better estimates of reservoir properties than the less complete (elastic) model parameterization. [Formula: see text] and [Formula: see text] are sensitive primarily to fluid types and saturations. The parameter correlations are sensitive also to the model parameterization. As noise increases in the viscoelastic input data, the resolution of the estimated parameters decreases, but the parameter correlations are relatively unaffected by modest noise levels.

Geostatistical Inversion in Carbonate Reservoirs to Map Reservoir Quality With High Predictability – A Case Study From Onshore Abu Dhabi

2021 ◽  
Author(s):  
S Al Naqbi ◽  
J Ahmed ◽  
J Vargas Rios ◽  
Y Utami ◽  
A Elila ◽  
...  
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Pore Volume ◽  
Rock Physics ◽  
Static Model ◽  
Reservoir Quality ◽  
Reservoir Properties ◽  
Geostatistical Inversion ◽  
High Predictability ◽  
The Impact

Abstract The Thamama group of reservoirs consist of porous carbonates laminated with tight carbonates, with pronounced lateral heterogeneities in porosity, permeability, and reservoir thickness. The main objective of our study was mapping variations and reservoir quality prediction away from well control. As the reservoirs were thin and beyond seismic resolution, it was vital that the facies and porosity be mapped in high resolution, with a high predictability, for successful placement of horizontal wells for future development of the field. We established a unified workflow of geostatistical inversion and rock physics to characterize the reservoirs. Geostatistical inversion was run in static models that were converted from depth to time domain. A robust two-way velocity model was built to map the depth grid and its zones on the time seismic data. This ensured correct placement of the predicted high-resolution elastic attributes in the depth static model. Rock physics modeling and Bayesian classification were used to convert the elastic properties into porosity and lithology (static rock-type (SRT)), which were validated in blind wells and used to rank the multiple realizations. In the geostatistical pre-stack inversion, the elastic property prediction was constrained by the seismic data and controlled by variograms, probability distributions and a guide model. The deterministic inversion was used as a guide or prior model and served as a laterally varying mean. Initially, unconstrained inversion was tested by keeping all wells as blind and the predictions were optimized by updating the input parameters. The stochastic inversion results were also frequency filtered in several frequency bands, to understand the impact of seismic data and variograms on the prediction. Finally, 30 wells were used as input, to generate 80 realizations of P-impedance, S-impedance, Vp/Vs, and density. After converting back to depth, 30 additional blind wells were used to validate the predicted porosity, with a high correlation of more than 0.8. The realizations were ranked based on the porosity predictability in blind wells combined with the pore volume histograms. Realizations with high predictability and close to the P10, P50 and P90 cases (of pore volume) were selected for further use. Based on the rock physics analysis, the predicted lithology classes were associated with the geological rock-types (SRT) for incorporation in the static model. The study presents an innovative approach to successfully integrate geostatistical inversion and rock physics with static modeling. This workflow will generate seismically constrained high-resolution reservoir properties for thin reservoirs, such as porosity and lithology, which are seamlessly mapped in the depth domain for optimized development of the field. It will also account for the uncertainties in the reservoir model through the generation of multiple equiprobable realizations or scenarios.

Sign in / Sign up

Export Citation Format

Share Document