scholarly journals Seismically detected porous Zechstein carbonates in Southern Jutland, Denmark

1995 ◽  
Vol 42 ◽  
pp. 34-46
Author(s):  
Kim Gunn Maver
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Seismic Reflection ◽  
Synthetic Seismograms ◽  
Lateral Distribution ◽  
Seismic Modelling ◽  
Seismic Sections ◽  
Well Data ◽  
Impedance Models

Zechstein carbonates in Southern Jutland, Denmark, have been explored by 10 wells since 1952, and a total of more than 2000 km of 2D seismic data has been acquired by various contractors. Seismic modelling, based on all the well data, is used as an aid to predict the lateral distribution of porous Zechstein carbonate intervals from the seismic data. ID seismic modelling is used to define the maximum number of intervals detected by the seismic sections at well locations. The ID seismic modelling results are also used to derive 2D acoustic impedance models and corresponding synthetic seismograms. The seismic modelling results illustrate a number of diagnostic reflection patterns associated with the porous carbonate intervals. The predicted distribution of porous carbonate intervals is, however, found to be uncertain, as thickness and porosity variations of each interval cannot be distinguished. Furthermore, thin porous carbonate intervals are not detected by the seismic sections, and the seismic reflection patterns indicating the presence of porous carbonate intervals can be associated with other lithologies. Porous Ca-la, Ca-lb, Ca-2 and Ca-3 carbonate intervals are found to be detected by the seismic sections only in the Zechstein platform area, and only the porous Ca-2 carbonate interval can be mapped

Geophysical tutorial: Well-tie calculus

2014 ◽  
Vol 33 (6) ◽  
pp. 674-677 ◽  
Author(s):  
Evan Bianco
Keyword(s):  
Seismic Data ◽  
Synthetic Seismograms ◽  
Proprietary Software ◽  
The Third ◽  
Geologic Interpretation ◽  
Well Data

Welcome to the third tutorial in this series. Evan Bianco has put together a terrific look at 1D synthetic seismograms — the critical connections between well data and seismic data that make geologic interpretation possible. Most of us use proprietary software for this part of the workflow, but do you really know what's going on in there? My challenge is: Take a couple of hours, install IPython from ipython.org , and see if you can work your way through Bianco's Notebook at github.com/seg/tutorials — I guarantee you will learn something. If you get stuck, please reach out to him.

Seismic expression of salt tectonics in the Sab’atayn Basin, onshore Yemen

2014 ◽  
Vol 2 (4) ◽  
pp. SM91-SM100 ◽  
Author(s):  
Gabor Tari ◽  
Rudi Dellmour ◽  
Emma Rodgers ◽  
Shaista Sultan ◽  
Abdo Al Atabi ◽  
...  
Keyword(s):  
Seismic Data ◽  
Strong Correlation ◽  
Seismic Reflection ◽  
Upper Jurassic ◽  
Salt Tectonics ◽  
3D Seismic ◽  
Flip Flop ◽  
Well Data ◽  
Tectonic Features ◽  
3D Seismic Data

A variety of distinct salt tectonic features are present in the Sab’atayn Basin of western Yemen. Based on the interpretation of 2D/3D seismic data and exploration wells in the central part of the basin, an Upper Jurassic evaporite unit produced numerous salt rollers, salt pillows, reactive, flip-flop, and falling diapirs. Halokinetics began as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab’atayn evaporite sequence. The significant proportions of nonevaporite lithologies within the “salt” made the seismic interpretation of the salt features challenging. The evaporite sequence had been described by most as a syn-rift unit and therefore a strong correlation was assumed between the subsalt syn-rift basement architecture and the overlying diapirs and other salt-related features. However, seismic reflection and well data revealed a nonsystematic relationship between the salt diapirs and the subsalt basement highs. This observation has very important implications for the subsalt fractured basement play in the Sab’atayn Basin.

scholarly journals Use of Attributes on 3D Seismic Data for Studying Mishrif Formation in East Abu-Amoud Field, South-Eastern Iraq

2021 ◽  
pp. 4802-4809
Author(s):  
Mohammed H. Al-Aaraji ◽  
Hussein H. Karim
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Seismic Attributes ◽  
3D Seismic ◽  
Seismic Section ◽  
Reflected Waves ◽  
South Eastern ◽  
Seismic Sections ◽  
Sonic Logs ◽  
3D Seismic Data

      The seismic method depends on the nature of the reflected waves from the interfaces between layers, which in turn depends on the density and velocity of the layer, and this is called acoustic impedance. The seismic sections of the East Abu-Amoud field that is located in Missan Province, south-eastern Iraq, were studied and interpreted for updating the structural picture of the major Mishrif Formation for the reservoir in the field. The Mishrif Formation is rich in petroleum in this area, with an area covering about 820 km2. The horizon was calibrated and defined on the seismic section with well logs data (well tops, check shot, sonic logs, and density logs) in the interpretation process to identify the upper and lower boundaries of the Formation.  Seismic attributes were used to study the formation, including instantaneous phase attributes and relative acoustic impedance on time slice of 3D seismic data . Also, relative acoustic impedance was utilized to study the top of the Mishrif Formation. Based on these seismic attributes, karst features of the formation were identified. In addition, the nature of the lithology in the study area and the change in porosity were determined through the relative acoustic impedance The overlap of the top of the Mishrif Formation with the bottom of the Khasib Formation was determined because the Mishrif Formation is considered as an unconformity surface.

scholarly journals 2D Seismic Structural and Stratigraphic Study of Kirkuk Group Formation in Amara Oil Field- Southeastern Iraq

2021 ◽  
pp. 3942-3951
Author(s):  
Ali K. Jaheed ◽  
Hussein H. Karim
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Sedimentary Basin ◽  
Group Formation ◽  
Structural Features ◽  
Field Structure ◽  
Synthetic Seismograms ◽  
Oil Field ◽  
Well Logs ◽  
Depth Maps

The Amarah Oil field structure was studied and interpreted by using 2-D seismic data obtained from the Oil  Exploration company. The study is concerned with Maysan Group Formation (Kirkuk Group) which is located in southeastern Iraq and belongs to the Tertiary Age. Two reflectors were detected based on synthetic seismograms and well logs (top and bottom Missan Group). Structural maps were derived from seismic reflection interpretations to obtain the location and direction of the sedimentary basin. Two-way time and depth maps were conducted depending on the structural interpretation of the picked reflectors to show several structural features. These included three types of closures, namely two anticlines extended in the directions of S-SW and NE, one nose structure (anticline) in the middle of the study area,  and structural faults in the northeastern part of the area, which is consistent with the general fault pattern. The seismic interpretation showed the presence of some stratigraphic features. Stratigraphic trap at the eastern part of the field, along with other phenomena, such as flatspot (mound), lenses, onlap, and toplap, were detected as indications of potential hydrocarbon accumulation in the region.

Locating faults in underground coal mines using high‐resolution seismic reflection techniques

Geophysics ◽  
1989 ◽  
Vol 54 (12) ◽  
pp. 1521-1527 ◽  
Author(s):  
Lawrence M. Gochioco ◽  
Steven A. Cotten
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Seismic Reflection ◽  
Coal Mines ◽  
Seismic Source ◽  
Seismic Survey ◽  
Underground Coal Mines ◽  
Vertical Displacements ◽  
Seismic Sections ◽  
Mine Development

A high‐resolution seismic reflection technique was used to locate faults in coal seams that were not visible on the surface and could only be observed in underground coal mines. An 8‐gauge buffalo gun, built by the research and development department of Consolidation Coal Company, was used as the seismic source. The coal seam at a depth of 700 ft produces a reflection with a predominant frequency of about 125 Hz. The high‐resolution seismic data permitted faults with vertical displacements of the same magnitude as the seam thickness to be detected at depths of several hundred feet beneath the surface. Several faults were detected and interpreted from the seismic sections, and the magnitudes of their displacement were estimated by matching the recorded seismic data to synthetic seismic data. Subsequent underground mine development in the study area confirmed two interpreted faults and their estimated displacements. Mining engineers were able to use the information provided by the seismic survey to plan an entry system through the fault zone so that less rock needed to be mined, resulting in a safer and more productive mine.

Geostatistical seismic inversion for frontier exploration

2017 ◽  
Vol 5 (4) ◽  
pp. T477-T485 ◽  
Author(s):  
Ângela Pereira ◽  
Rúben Nunes ◽  
Leonardo Azevedo ◽  
Luís Guerreiro ◽  
Amílcar Soares
Keyword(s):  
Acoustic Impedance ◽  
Seismic Reflection ◽  
Seismic Inversion ◽  
Well Log ◽  
Data Set ◽  
Seismic Reflection Data ◽  
Log Data ◽  
The Real ◽  
Reflection Data ◽  
Impedance Models

Numerical 3D high-resolution models of subsurface petroelastic properties are key tools for exploration and production stages. Stochastic seismic inversion techniques are often used to infer the spatial distribution of the properties of interest by integrating simultaneously seismic reflection and well-log data also allowing accessing the spatial uncertainty of the retrieved models. In frontier exploration areas, the available data set is often composed exclusively of seismic reflection data due to the lack of drilled wells and are therefore of high uncertainty. In these cases, subsurface models are usually retrieved by deterministic seismic inversion methodologies based exclusively on the existing seismic reflection data and an a priori elastic model. The resulting models are smooth representations of the real complex geology and do not allow assessing the uncertainty. To overcome these limitations, we have developed a geostatistical framework that allows inverting seismic reflection data without the need of experimental data (i.e., well-log data) within the inversion area. This iterative geostatistical seismic inversion methodology simultaneously integrates the available seismic reflection data and information from geologic analogs (nearby wells and/or analog fields) allowing retrieving acoustic impedance models. The model parameter space is perturbed by a stochastic sequential simulation methodology that handles the nonstationary probability distribution function. Convergence from iteration to iteration is ensured by a genetic algorithm driven by the trace-by-trace mismatch between real and synthetic seismic reflection data. The method was successfully applied to a frontier basin offshore southwest Europe, where no well has been drilled yet. Geologic information about the expected impedance distribution was retrieved from nearby wells and integrated within the inversion procedure. The resulting acoustic impedance models are geologically consistent with the available information and data, and the match between the inverted and the real seismic data ranges from 85% to 90% in some regions.

scholarly journals Reservoir Characterizarion Using Acoustic Impedance Inversion and Multi-Attribute Analysis in Nias Waters, North Sumatra

2019 ◽  
Vol 34 (1) ◽  
Author(s):  
Fathkhurozak Yunanda Rifai ◽  
Tumpal Bernhard Nainggolan ◽  
Henry Munandar Manik
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Source Rocks ◽  
Time Migration ◽  
Attribute Analysis ◽  
Impedance Inversion ◽  
Acoustic Impedance Inversion ◽  
Well Data ◽  
North Sumatra ◽  
Rock Lithology

Seismic method is one of the most frequently applied geophysical methods in the process of oil and gas exploration. This research is conducted in Nias Waters, North Sumatra using one line 2D post-stack time migration seismic section and two wells data. Reservoir characterization is carried out to obtain physical parameters of rocks affected by fluid and rock lithology. Seismic inversion is used as a technique to create acoustic impedance distribution using seismic data as input and well data as control. As final product, multi-attribute analysis is applied to integrate of inversion results with seismic data to determine the lateral distribution of other parameters contained in well data. In this research, multi-attribute analysis is used to determine the distribution of NPHI as a validation of hydrocarbon source rocks. In that area, there is a gas hydrocarbon prospect in limestone lithology in depth around 1450 ms. Based on the results of sensitivity analysis, cross-plot between acoustic impedance and NPHI are sensitive in separating rock lithology, the target rock in the form of limestone has physical characteristics in the form of acoustic impedance values in the range of 20,000-49,000 ((ft/s)*(g/cc)) and NPHI values in the range of 5-35 %. While the results of the cross-plot between the acoustic impedance and resistivity are able to separate fluid-containing rocks with resistivity values in the range about 18-30 ohmm. The result of acoustic impedance inversion using the model based method shows the potential for hydrocarbons in the well FYR-1 with acoustic impedance in the range 21,469-22,881 ((ft/s)*(gr/cc)).

THE JOHN BROOKES GAS DISCOVERY—AN EVOLVING STORY

2002 ◽  
Vol 42 (1) ◽  
pp. 443
Author(s):  
K. Auld ◽  
B. Thomas ◽  
J. Goodall ◽  
J. Benson
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Complex Model ◽  
Work Commitment ◽  
Seismic Modelling ◽  
3D Data ◽  
Stratigraphic Model ◽  
Well Data ◽  
Structural Closure ◽  
Confined Channel

John Brookes–1 was drilled as part of a work commitment for the WA-214-P Joint Venture in 1998 and discovered an 85 m gross dry gas column. The objective of the well was to test a structural closure at the base of the Muderong Shale regional seal on the Tryal Rocks anticline, up-dip from Tryal Rocks–1, drilled in 1970. Tryal Rocks–1, the 31st offshore well to be drilled within the Carnarvon Basin, WA, was initially considered a dry hole. However, a review of the well data in 1997–98 suggested that Tryal Rocks–1 might contain a hydrocarbon column. The mapping of the structure using initially 2D seismic data acquired post Tryal Rocks–1, then 3D data, indicated that Tryal Rocks–1 was drilled within closure, but off crest, and that significant closure existed up-dip. The John Brookes–1 location was selected to test this updip potential. The John Brookes–1 discovery confirmed the validity of the structural mapping. However, the unexpected nature of the reservoir, interpreted as a well developed turbiditic channel of Birdrong Sandstone age, changed the emphasis from purely structural to a play with structural/stratigraphic potential. An amalgamated turbidite complex model was invoked which infers that the John Brookes–1 reservoir represents a confined channel system cut into the underlying substrate. This model explains the results to date, with the John Brookes–1 gas reservoir being in direct continuity with the sandstones at Tryal Rocks–1. A review of the 3D seismic data across the field and seismic modelling support the stratigraphic model developed from the palynological interpretation.

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