Seismic-based characterization of reservoir heterogeneity within the Meramec interval of the STACK play, Central Oklahoma

2020 ◽  
pp. 1-46
Author(s):  
William Neely ◽  
Ahmed Ismail ◽  
Mohammed Ibrahim ◽  
James Puckette
Keyword(s):  
Oil And Gas ◽  
Seismic Inversion ◽  
Well Logs ◽  
Reservoir Quality ◽  
High Porosity ◽  
3D Seismic ◽  
Horizontal Drilling ◽  
Wide Range ◽  
Porosity Heterogeneity

The Meramec interval within the “STACK” play of the Anadarko Basin in central Oklahoma has been recently at the epicenter of increased exploration and production of oil and gas. It has become one of the top target intervals of the “Mid-Continent” aided by the technological advancements in horizontal drilling and completion techniques. The Meramec interval, mainly composed of argillaceous siliciclastic sediments with varying amounts of carbonate cement, exhibits high porosity heterogeneity, which is theorized to be caused by varying amounts of clay and post-depositional calcite cement. Characterization of the porosity heterogeneity in the Meramec interval will improve our understanding of the wide range in Meramec oil and gas production volumes and reduce the risk associated with drilling and completion techniques. We completed an initial interpretation followed by inversion of 3D seismic data where we generated a detailed characterization of the porosity heterogeneity and overall reservoir quality within the Meramec interval over an area of approximately 150 square kilometers. We then used the 3D seismic volume and available well logs to map the vertical and lateral extents of the Meramec interval and identify possible structural elements that could affect the reservoir quality. A petrophysical analysis of the well logs confirmed porosity heterogeneity and variations in volumetric calculations of clay and carbonate minerals. Finally, we generated a set of porosity volumes using the acoustic impedance from seismic inversion and probabilistic neural network methods. The derived porosity volume helped us identify porous and non-porous intervals within the Meramec throughout the study area. The results improved our understanding of Meramec heterogeneity, further reducing the risk associated with well planning, drilling and completion.

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.

Integrating Laboratory Testing and Numerical Modelling for a Giant Maturing Carbonate Field in UAE — II. Coupled Geomechanical Modelling of Stacked Reservoir Intervals

2021 ◽  
Author(s):  
Abdelwahab Noufal ◽  
Gaisoni Nasreldin ◽  
Faisal Al-Jenaibi ◽  
Joel Wesley Martin ◽  
Julian Guerra ◽  
...  
Keyword(s):  
Stress State ◽  
Oil And Gas ◽  
Water Injection ◽  
Seismic Inversion ◽  
Second Phase ◽  
High Porosity ◽  
Pore Collapse ◽  
Reservoir Compaction ◽  
Stress Changes ◽  
Field Management

Abstract A mature field located in a gently dipping structure onshore Abu Dhabi has multiple stacked oil and gas reservoirs experiencing different levels of depletion. The average reservoir pressure in some of these intervals had declined from the early production years to the present day by more than 2000 psi. Coupled geomechanical modelling is, therefore, of the greatest value to predict the stress paths in producing reservoir units, using the concept of effective stress. This paper examines the implications for long-term field management—focusing primarily on estimating the potential for reservoir compaction and predicting field subsidence. This paper takes the work reported in Noufal et al. (2020) one step further by integrating the results of a comprehensive geomechanical laboratory characterization study designed to assess the potential geomechanical changes in the stacked reservoirs from pre-production conditions to abandonment. This paper adopts a geomechanical modelling approach integrating a wide array of data—including prestack seismic inversion outputs and dynamic reservoir simulation results. This study comprised four phases. After the completion of rock mechanics testing, the first modelling phase examined geomechanics on a fine scale around individual wells. The goal of the second phase was to build 4D mechanical earth models (4D MEMs) by incorporating 14 reservoir models—resulting in one of the largest 4D MEMs ever built worldwide. The third phase involved determining the present-day stress state—matching calibrated post-production 1D MEMs and interpreted stress features. Lastly, the resulting model was used for field management and formation stimulation applications. The 4D geomechanical modelling results indicated stress changes in the order of several MPa in magnitude compared with the pre-production stress state, and some changes in stress orientations, especially in the vicinity of faults. This was validated using well images and direct stress measurements, indicating the ability of the 4D MEM to capture the changes in stress magnitudes and orientations caused by depletion. In the computed results, the 4D MEM captures the onset of pore collapse and its accelerating response as observed in the laboratory tests conducted on cores taken from different reservoir units. Pore collapse is predicted in later production years in areas with high porosity, and it is localized. The model highlights the influence of stress changes on porosity and permeability changes over time, thus providing insights into the planning of infill drilling and water injection. Qualitatively, the results provide invaluable insights into delineating potential sweet spots for stimulation by hydraulic fracturing.

Fatehgarh lacustrine turbidite potential, Barmer Basin, India

2019 ◽  
Vol 38 (4) ◽  
pp. 280-285
Author(s):  
Priyabrata Chatterjee ◽  
Utpalendu Kuila ◽  
B. N. S. Naidu ◽  
Hriday Jyoti Bora ◽  
Anil Malkani ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Integrated Approach ◽  
Seismic Inversion ◽  
Seismic Facies ◽  
Reservoir Quality ◽  
High Quality ◽  
Passive Margins ◽  
Seismic Waveform ◽  
Barmer Basin ◽  
Environment Maps

Global discovered resources of oil and gas in giant stratigraphic and structural-stratigraphic combination traps have increased by nearly 50% in the last 17 years. Among the biggest contributors are the large discoveries in deepwater turbidite systems in passive margins and rift basins. The current study area is located in the Barmer Basin in northwestern India. Barmer Basin is a prolific petroliferous basin with major oil discoveries in structural plays including Mangala, Bhagyam, and Aishwariya fields. The principal reservoirs in the structural highs are high-quality fluvial sandstones of the Paleocene Fatehgarh Formation. Lacustrine turbidite plays have been discovered in the overlying Paleocene Barmer Hill Formation, albeit with moderate to poor reservoir quality. The potential exists, however, for finding off-structure lacustrine deepwater turbidite plays in the Paleocene Fatehgarh with reservoir quality comparable to the high-quality fluvial facies encountered updip in the structural plays. An integrated approach was adopted to identify stratigraphic entrapments across the basin to chase high-quality Fatehgarh reservoirs. Gross depositional environment maps integrating new geoscientific data were created, followed by well-calibrated seismic geomorphology and seismic facies interpretations to identify the distal lacustrine deepwater turbidite system fed by the updip fluvial Fatehgarh systems. Worldwide, the critical risk elements associated with such plays are reservoir presence, quality, and lateral seal. Geophysical tools like unsupervised seismic waveform classification, spectral decomposition, and seismic inversion were applied to the available seismic data, and the results were integrated with the regional geology and well facies information to derisk the critical risk segments.

Reflectivity decomposition: Theory and application

2021 ◽  
pp. 1-57
Author(s):  
Chen Liang ◽  
John Castagna ◽  
Marcelo Benabentos
Keyword(s):  
Seismic Data ◽  
Seismic Inversion ◽  
Well Logs ◽  
Reflection Coefficients ◽  
3D Seismic ◽  
Decomposition Theory ◽  
Midland Basin ◽  
Reflection Seismic ◽  
Sparse Inversion ◽  
Reflectivity Inversion

Sparse reflectivity inversion of processed reflection seismic data is intended to produce reflection coefficients that represent boundaries between geological layers. However, the objective function for sparse inversion is usually dominated by large reflection coefficients which may result in unstable inversion for weak events, especially those interfering with strong reflections. We propose that any seismogram can be decomposed according to the characteristics of the inverted reflection coefficients which can be sorted and subset by magnitude, sign, and sequence, and new seismic traces can be created from only reflection coefficients that pass sorting criteria. We call this process reflectivity decomposition. For example, original inverted reflection coefficients can be decomposed by magnitude, large ones removed, the remaining reflection coefficients reconvolved with the wavelet, and this residual reinverted, thereby stabilizing inversions for the remaining weak events. As compared with inverting an original seismic trace, subtle impedance variations occurring in the vicinity of nearby strong reflections can be better revealed and characterized when only the events caused by small reflection coefficients are passed and reinverted. When we apply reflectivity decomposition to a 3D seismic dataset in the Midland Basin, seismic inversion for weak events is stabilized such that previously obscured porous intervals in the original inversion, can be detected and mapped, with good correlation to actual well logs.

scholarly journals Pore Type and Porosity Distribution of Carbonate Reservoir Based on 3D Seismic Inversion in “P” Field Salawati Basin

2019 ◽  
Vol 125 ◽  
pp. 15002
Author(s):  
Avishena Prananda ◽  
Mohammad Syamsu Rosid ◽  
Robet Wahyu Widodo
Keyword(s):  
Acoustic Impedance ◽  
Carbonate Rock ◽  
Sedimentary Rock ◽  
Seismic Inversion ◽  
Carbonate Reservoir ◽  
High Porosity ◽  
3D Seismic ◽  
Impedance Distribution ◽  
Pore Types ◽  
Type Classification

Overall, carbonate rock has complex and more heterogeneous physical characteristic, compared to siliciclastic sedimentary rock. One parameter, which distinguishes carbonate rock and siliciclastic is pore structure/pore type. The heterogeneity and complexity of carbonate reservoir pore type are affected by the sedimentation process and the diagenesis process. Pore type classification is divided into three: interparticle, stiff, and crack. Therefore, carbonate pore type determination becomes important to enhance drilling success. This paper explains pore types prediction, porosity, and acoustic impedance on carbonate reservoir. The Differential Effective Medium (DEM) method to analyze carbonate reservoir pore type has been applied. DEM method generates bulk and shear modulus parameters to create carbonate Vp and Vs model based on pore type. We also do a 3D seismic inversion to create acoustic impedance distribution, porosity, and pore type. Afterward, we made cube porosity and pore type cube by using geostatistics method to provide a better result. Moreover, this study shows low impedance value correlates with high porosity value and enhancement of porosity value correlates with crack and interparticle pore type on “P” field, Salawati Basin.

Seismic inversion for the parameters of two orthogonal fracture sets in a VTI background medium

Geophysics ◽  
2002 ◽  
Vol 67 (1) ◽  
pp. 292-299 ◽  
Author(s):  
Andrey Bakulin ◽  
Vladimir Grechka ◽  
Ilya Tsvankin
Keyword(s):  
Seismic Data ◽  
Fractured Reservoirs ◽  
Crack Density ◽  
Transversely Isotropic ◽  
Seismic Inversion ◽  
Naturally Fractured Reservoirs ◽  
Multiple Fracture ◽  
Effective Parameters ◽  
Wide Range

Characterization of naturally fractured reservoirs often requires estimating parameters of multiple fracture sets that develop in an anisotropic background. Here, we discuss modeling and inversion of the effective parameters of orthorhombic models formed by two orthogonal vertical fracture sets embedded in a VTI (transversely isotropic with a vertical symmetry axis) background matrix. Although the number of the microstructural (physical) medium parameters is equal to the number of effective stiffness elements (nine), we show that for this model there is an additional relation (constraint) between the stiffnesses or Tsvankin's anisotropic coefficients. As a result, the same effective orthorhombic medium can be produced by a wide range of equivalent models with vastly different fracture weaknesses and background VTI parameters, and the inversion of seismic data for the microstructural parameters is nonunique without additional information. Reflection moveout of PP‐ and PS‐waves can still be used to find the fracture orientation and estimate (in combination with the vertical velocities) the differences between the normal and shear weaknesses of the fracture sets, as well as the background anellipticity parameter ηb. Since for penny‐shaped cracks the shear weakness is close to twice the crack density, seismic data can help to identify the dominant fracture set, although the crack densities cannot be resolved individually. If the VTI symmetry of the background is caused by intrinsic anisotropy (as is usually the case for shales), it may be possible to determine at least one background anisotropic coefficient from borehole or core measurements. Then seismic data can be inverted for the fracture weaknesses and the rest of the background parameters. Therefore, seismic characterization of reservoirs with multiple fracture sets and anisotropic background is expected to give ambiguous results, unless the input data include measurements made on different scales (surface seismic, borehole, cores).

Hydrocarbon reservoir characterization of “AY” field, deep-water Niger Delta using 3D seismic and well logs

2017 ◽  
Vol 10 (6) ◽  
Author(s):  
Oluseun Adetola Sanuade ◽  
Adesoji Olumayowa Akanji ◽  
Michael Adeyinka Oladunjoye ◽  
Abayomi Adesola Olaojo ◽  
Julius O. Fatoba
Keyword(s):  
Deep Water ◽  
Niger Delta ◽  
Reservoir Characterization ◽  
Well Logs ◽  
3D Seismic ◽  
Hydrocarbon Reservoir

scholarly journals Porosity estimation in the Fort Worth Basin constrained by 3D seismic attributes integrated in a sequential Bayesian simulation framework

Geophysics ◽  
2017 ◽  
Vol 82 (4) ◽  
pp. M67-M80 ◽  
Author(s):  
Martin Blouin ◽  
Mickaele Le Ravalec ◽  
Erwan Gloaguen ◽  
Mathilde Adelinet
Keyword(s):  
Oil And Gas ◽  
Reservoir Characterization ◽  
Geophysical Methods ◽  
Seismic Attributes ◽  
Seismic Inversion ◽  
Fort Worth ◽  
3D Seismic ◽  
Reservoir Properties ◽  
Fort Worth Basin ◽  
Porosity Estimation

The accurate inference of reservoir properties such as porosity and permeability is crucial in reservoir characterization for oil and gas exploration and production as well as for other geologic applications. In most cases, direct measurements of those properties are done in wells that provide high vertical resolution but limited lateral coverage. To fill this gap, geophysical methods can often offer data with dense 3D coverage that can serve as proxy for the variable of interest. All the information available can then be integrated using multivariate geostatistical methods to provide stochastic or deterministic estimate of the reservoir properties. Our objective is to generate multiple scenarios of porosity at different scales, considering four formations of the Fort Worth Basin altogether and then restricting the process to the Marble Falls limestones. Under the hypothesis that a statistical relation between 3D seismic attributes and porosity can be inferred from well logs, a Bayesian sequential simulation (BSS) framework proved to be an efficient approach to infer reservoir porosity from an acoustic impedance cube. However, previous BBS approaches only took two variables upscaled at the resolution of the seismic data, which is not suitable for thin-bed reservoirs. We have developed three modified BSS algorithms that better adapt the BSS approach for unconventional reservoir petrophysical properties estimation from deterministic prestack seismic inversion. A methodology that includes a stochastic downscaling procedure is built and one that integrates two secondary downscaled constraints to the porosity estimation process. Results suggest that when working at resolution higher than surface seismic, it is better to execute the workflow for each geologic formation separately.

scholarly journals Pre-stack seismic inversion based on a genetic algorithm: A case from the llanos basin (Colombia) in the absence of well information

2012 ◽  
Vol 4 (5) ◽  
pp. 05-20 ◽  
Author(s):  
Edward Moncayo ◽  
Nadejda Tchegliakova ◽  
Luis Montes
Keyword(s):  
Genetic Algorithm ◽  
Rock Physics ◽  
Real Data ◽  
Seismic Inversion ◽  
Well Logs ◽  
High Porosity ◽  
Seismic Line ◽  
Porosity And Permeability ◽  
Borehole Logs ◽  
Prospective Risk

The Llanos basin is the most prolific of the Colombian basins; however few stratigraphic plays have been explored due to the uncertainty in determining the lithology of the channels. Inside a migrated 2D section, a wide channel was identified inside a prospective sandy unit of the Carbonera Formation, composed by intercalations of sand and shale levels, and considered a main reservoir in this part of the basin. However, the lithology filling the channel was unknown due to the absence of wells. To infer the channel lithology, and diminish the prospective risk a model based pre-stack seismic inversion was proposed.However, without well logs available along the line, the uncertain initial model diminishes reliance on the inversion. To circumvent this impasse, a seismic inversion with a genetic algorithm was proposed. The algorithm was tested on synthetic seismograms and real data from an area of the basin, where well logs were available. The error analysis between the expected and the inverted results, in both scenarios, pointed out a good algorithmic performance. Then, the algorithm was applied to the pre stack data of the 2D line where the channel had been identified.According to the inverted results and rock physics analysis of wells near the seismic line with comparative geology, classified the channel was described as to be filled by silt, shale and probably some levels of shaly sands, increasing the exploratory risk because this lithology has low porosity and permeability, contrary to the producing reservoirs in neighbor fields, characterized by clean sands of high porosity. The algorithm is useful in areas with few or no borehole logs.

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