scholarly journals Application of geophysical methods in the extrapolation of sedimentological data on unmastered areas of deposits (on the example of Pennsylvanian carbonate reservoir, Akanskoye oilfield, east of Russian Platform)

2021 ◽  
pp. 128-134
Author(s):  
B. V. Platov ◽  
◽  
A. N. Kolchugin ◽  
E. A. Korolev ◽  
D. S. Nikolaev ◽  
...  
Keyword(s):  
Seismic Data ◽  
Geophysical Methods ◽  
Russian Platform ◽  
Carbonate Reservoir ◽  
Reservoir Properties ◽  
Reservoir Characteristics ◽  
The North ◽  
Study Results ◽  
Core Study ◽  
Well Data

A feature of the oil-bearing carbonate deposits of the lower Pennsylvanian in the east of the Russian platform is their rapid vertical and horizontal change. It is often difficult to make correlations between sections, especially in the absence of core data when using only geophysical data. In addition, not all facies are reliably identified and traceable from log data and not all have high reservoir properties. Authors made an attempt to trace the promising facies both to adjacent wells and, in general, to the entire field area using core study results and translation of these results using log and seismic data. The data showed pinching of rocks with high reservoir characteristics in the direction of the selected profile (from south to north within the field). Coastal shallow water facies, represented by Grainstones and Packstones, with high reservoir properties in the south of the field, are replaced by lagoon facies and facies of subaerial exposures, represented by Wakestones and Mudstones with low reservoir characteristics, in the north of the field. The authors suggest that this approach can be applicable for rocks both in this region and for areas with a similar structure. Keywords: pinch-out; well data; seismic data; limestone; facies; reservoir rocks.

Shell's integrated quantitative interpretation workflow

2011 ◽  
Vol 51 (2) ◽  
pp. 681
Author(s):  
Frank Glass ◽  
Stephan Gelinsky ◽  
Irene Espejo ◽  
Teresa Santana ◽  
Gareth Yardley
Keyword(s):  
Seismic Data ◽  
Rock Properties ◽  
Well Log ◽  
Reservoir Properties ◽  
North West ◽  
The North ◽  
Fluid Properties ◽  
Well Data ◽  
Acoustic Responses ◽  
Carnarvon Basin

Shell Development Australia is a major asset holder in the Browse Basin and the Carnarvon Basin in the North West Shelf of Australia. In 2007, Shell Development Australia embarked on an integrated quantitative seismic interpretation project related to the Triassic Mungaroo Formation in the Carnarvon Basin. The main objective was to constrain the uncertainties in using seismic data as a predictor for rock and fluid properties of fields and prospects in the basin. This project followed a workflow that has been proven in other basins around the world, whereby the vertical and lateral variability of rock properties of both reservoir and non-reservoir lithologies are captured in general trends. The calculated trends are based on well log extractions of end member lithologies and the input of petrographic information and forward modelling. In combination with a regionally consistent 3D burial model for the estimation of remaining porosity, these established rock trends then allow for a prediction of various acoustic responses of reservoir and pore fill properties. The comparisons between the pre-drill predicted rock properties and the properties encountered after drilling at different reservoir levels have lead to a general confidence that the reservoir properties can be derived from seismic data where well data are not abundant. This increased confidence will play a major part in Shell’s attitude towards appraisal activities and decisions on various development options.

Stochastic inversion by trace matching for carbonate reservoir property prediction: A Mishrif Reservoir case study

2019 ◽  
Vol 38 (1) ◽  
pp. 27-34 ◽  
Author(s):  
Sara R. Grant ◽  
Matthew J. Hughes ◽  
O. J. Olatoke ◽  
Neil Philip
Keyword(s):  
Seismic Data ◽  
Carbonate Reservoir ◽  
Inversion Process ◽  
Reservoir Properties ◽  
Stochastic Inversion ◽  
Large Numbers ◽  
Well Data ◽  
Established Technique

Estimation of reservoir properties and facies from seismic data is a well-established technique, and there are numerous methods in common usage. Our 1D stochastic inversion process (ODiSI), based on matching large numbers of pseudowells to color-inverted angle stacks, produces good estimations of reservoir properties, facies probabilities, and associated uncertainties. Historically, ODiSI has only been applied to siliciclastic reservoir intervals. However, the technique is equally suited to carbonate reservoirs, and ODiSI gives good results for the Mishrif Reservoir interval in the Rumaila Field in Iraq. Of course, a thorough awareness of the quality of all input well data and detailed validation of the parameters input to the inversion process is crucial to understanding the accuracy of the results.

Extensive, Gas-charged Quaternary Sand Accumulations of the Northern North Sea and North Sea Fan

2020 ◽  
Author(s):  
Benjamin Bellwald ◽  
Sverre Planke ◽  
Sunil Vadakkepuliyambatta ◽  
Stefan Buenz ◽  
Christine Batchelor ◽  
...  
Keyword(s):  
North Sea ◽  
Seismic Data ◽  
Data Sets ◽  
3D Seismic ◽  
Fine Grained ◽  
The North ◽  
Northern North Sea ◽  
Well Data ◽  
Sea Fan ◽  
3D Seismic Data

<p>Sediments deposited by marine-based ice sheets are dominantly fine-grained glacial muds, which are commonly known for their sealing properties for migrating fluids. However, the Peon and Aviat hydrocarbon discoveries in the North Sea show that coarse-grained glacial sands can occur over large areas in formerly glaciated continental shelves. In this study, we use conventional and high-resolution 2D and 3D seismic data combined with well information to present new models for large-scale fluid accumulations within the shallow subsurface of the Norwegian Continental Shelf. The data include 48,000 km<sup>2</sup> of high-quality 3D seismic data and 150 km<sup>2</sup> of high-resolution P-Cable 3D seismic data, with a vertical resolution of 2 m and a horizontal resolution of 6 to 10 m in these data sets. We conducted horizon picking, gridding and attribute extractions as well as seismic geomorphological interpretation, and integrated the results obtained from the seismic interpretation with existing well data.</p><p>The thicknesses of the Quaternary deposits vary from hundreds of meters of subglacial till in the Northern North Sea to several kilometers of glacigenic sediments in the North Sea Fan. Gas-charged, sandy accumulations are characterized by phase-reserved reflections with anomalously high amplitudes in the seismic data as well as density and velocity decreases in the well data. Extensive (>10 km<sup>2</sup>) Quaternary sand accumulations within this package include (i) glacial sands in an ice-marginal outwash fan, sealed by stiff glacial tills deposited by repeated glaciations (the Peon discovery in the Northern North Sea), (ii) sandy channel-levee systems sealed by fine-grained mud within sequences of glacigenic debris flows, formed during shelf-edge glaciations, (iii) fine-grained glacimarine sands of contouritic origin sealed by gas hydrates, and (iv) remobilized oozes above large evacuation craters and sealed by megaslides and glacial muds. The development of the Fennoscandian Ice Sheet resulted in a rich variety of depositional environments with frequently changing types and patterns of glacial sedimentation. Extensive new 3D seismic data sets are crucial to correctly interpret glacial processes and to analyze the grain sizes of the related deposits. Furthermore, these data sets allow the identification of localized extensive fluid accumulations within the Quaternary succession and distinguish stratigraphic levels favorable for fluid accumulations from layers acting as fluid barriers.</p>

High-resolution reservoir characterization by an acoustic impedance inversion of a Tertiary deltaic clinoform system in the North Sea

Geophysics ◽  
2010 ◽  
Vol 75 (6) ◽  
pp. O57-O67 ◽  
Author(s):  
Daria Tetyukhina ◽  
Lucas J. van Vliet ◽  
Stefan M. Luthi ◽  
Kees Wapenaar
Keyword(s):  
North Sea ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Structural Information ◽  
Sampling Rate ◽  
Seismic Inversion ◽  
Acoustic Properties ◽  
The North ◽  
The North Sea ◽  
Well Data

Fluvio-deltaic sedimentary systems are of great interest for explorationists because they can form prolific hydrocarbon plays. However, they are also among the most complex and heterogeneous ones encountered in the subsurface, and potential reservoir units are often close to or below seismic resolution. For seismic inversion, it is therefore important to integrate the seismic data with higher resolution constraints obtained from well logs, whereby not only the acoustic properties are used but also the detailed layering characteristics. We have applied two inversion approaches for poststack, time-migrated seismic data to a clinoform sequence in the North Sea. Both methods are recursive trace-based techniques that use well data as a priori constraints but differ in the way they incorporate structural information. One method uses a discrete layer model from the well that is propagated laterally along the clinoform layers, which are modeled as sigmoids. The second method uses a constant sampling rate from the well data and uses horizontal and vertical regularization parameters for lateral propagation. The first method has a low level of parameterization embedded in a geologic framework and is computationally fast. The second method has a much higher degree of parameterization but is flexible enough to detect deviations in the geologic settings of the reservoir; however, there is no explicit geologic significance and the method is computationally much less efficient. Forward seismic modeling of the two inversion results indicates a good match of both methods with the actual seismic data.

Accuracy of wavelets, seismic inversion, and thin-bed resolution

2017 ◽  
Vol 5 (4) ◽  
pp. T523-T530
Author(s):  
Ehsan Zabihi Naeini ◽  
Mark Sams
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Low Frequency ◽  
Seismic Inversion ◽  
Inversion Method ◽  
Frequency Content ◽  
Frequency Model ◽  
North West ◽  
The North ◽  
Well Data

Broadband reprocessed seismic data from the North West Shelf of Australia were inverted using wavelets estimated with a conventional approach. The inversion method applied was a facies-based inversion, in which the low-frequency model is a product of the inversion process itself, constrained by facies-dependent input trends, the resultant facies distribution, and the match to the seismic. The results identified the presence of a gas reservoir that had recently been confirmed through drilling. The reservoir is thin, with up to 15 ms of maximum thickness. The bandwidth of the seismic data is approximately 5–70 Hz, and the well data used to extract the wavelet used in the inversion are only 400 ms long. As such, there was little control on the lowest frequencies of the wavelet. Different wavelets were subsequently estimated using a variety of new techniques that attempt to address the limitations of short well-log segments and low-frequency seismic. The revised inversion showed greater gas-sand continuity and an extension of the reservoir at one flank. Noise-free synthetic examples indicate that thin-bed delineation can depend on the accuracy of the low-frequency content of the wavelets used for inversion. Underestimation of the low-frequency contents can result in missing thin beds, whereas underestimation of high frequencies can introduce false thin beds. Therefore, it is very important to correctly capture the full frequency content of the seismic data in terms of the amplitude and phase spectra of the estimated wavelets, which subsequently leads to a more accurate thin-bed reservoir characterization through inversion.

The Paleozoic prospectivity of the Browse Basin, Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 685
Author(s):  
Said Amiribesheli ◽  
Joshua Thorp ◽  
Julia Davies
Keyword(s):  
Seismic Data ◽  
Inversion Algorithm ◽  
Reservoir Properties ◽  
Depth Migration ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Amplitude Versus Offset ◽  
Long Offset ◽  
Well Data

Most of the discovered hydrocarbons in the Browse Basin occurred within the Mesozoic intervals, while deeper Paleozoic sequences have been seldom explored. Lack of Paleozoic exploration in the Browse Basin has been attributed to the lack of well penetrations, poor understanding of the petroleum systems and paucity of seismic data. The onshore Canning Basin with several commercial fields and discoveries is the most appropriate analogue for understanding the Paleozoic sequences in the region. With the integration of geophysical data (i.e. gravity, magnetic and seismic), well data and geology, the Paleozoic prospectivity of the Browse Basin can be further enlightened. Modern long offset (8 m) Vampire 2D seismic data were acquired by Searcher to address some of the complex challenges in the Browse Basin. Reservoir quality of the Brewster Formation, volcanic discrimination within the Plover Formation and identification of deeper Triassic and Paleozoic plays are some examples of these challenges in the Browse Basin. Recently Searcher reprocessed this regionally important Vampire 2D seismic dataset that ties to 60 wells. The broadband pre-stack depth migration reprocessed data were inverted to extract three petro-elastic properties of acoustic impedance, Vp/Vs and density by three-term amplitude versus offset inversion algorithm to improve imaging of deeper plays and delineate reservoir properties. This paper discusses how several potential Paleozoic reservoir-seal pairs can be identified in the Browse Basin by utilising the integration of Vampire 2D seismic data, quantitative interpretation products, regional geology and knowledge of the Canning Basin’s fields and discoveries. Previously there was little exploration of Paleozoic plays because they could not be imaged on seismic data. The potential Paleozoic reservoirs identified in this study include Permo-Carboniferous subcrop, Carboniferous-Devonian anticline and Carboniferous-Devonian rollover plays.

THE GEOLOGY AND HYDROCARBON POTENTIAL OF THE NORTH-WESTERN OFFICER BASIN

1985 ◽  
Vol 25 (1) ◽  
pp. 52
Author(s):  
Bruce J. Phillips ◽  
Alan W. James ◽  
Graeme M. Philip
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Potential ◽  
Aeromagnetic Data ◽  
The North ◽  
Carbonate Sequence ◽  
Well Data ◽  
Regional Gravity ◽  
North Western

Recent petroleum exploration in EP 186 and EP 187 in the north-western Officer Basin has greatly increased knowledge of the regional stratigraphy, structure and petroleum prospectivity of the region. This exploration programme has involved the drilling of two deep stratigraphic wells (Dragoon 1 and Hussar 1) and the acquisition of 1438 km of seismic data. Integration of regional gravity and aeromagnetic data with regional seismic and well data reveals that the Gibson Sub-basin primarily contains a Proterozoic evaporitic sequence. In contrast, the Herbert Sub-basin contains a Late Proterozoic to Cambrian clastic and carbonate sequence above the evaporites. This sequence, which was intersected in Hussar 1, is identified as the primary exploration target in the Western Officer Basin. The sequence contains excellent reservoir and seal rocks in association with mature source rocks. Major structuring of the basin has also been caused by compressive movements associated with the Alice Springs Orogeny. The northwestern Officer Basin thus has all of the ingredients for the discovery of commercial hydrocarbons.

scholarly journals Reservoir characterisation using process-response simulations: the Lower Cretaceous Rijn Field, West Netherlands Basin

2003 ◽  
Vol 82 (4) ◽  
pp. 313-324
Author(s):  
L.J.H. Alberts ◽  
C.R. Geel ◽  
J.J. Klasen
Keyword(s):  
Seismic Data ◽  
Lower Cretaceous ◽  
Small Scale ◽  
Depositional Model ◽  
Response Model ◽  
Reservoir Properties ◽  
Reservoir Heterogeneity ◽  
Geological Processes ◽  
Basin Scale ◽  
Well Data

AbstractPetroleum geologists always need to deal with large gaps in data resolution and coverage during reservoir characterisation. Seismic data show only large geological structures, whereas small-scale structures and reservoir properties can be observed only at well locations. In the area between wells, these properties are often estimated by means of geostatistics. Numerical simulation of sedimentary processes offers an alternative method to predict these properties and can improve the understanding of the controls on reservoir heterogeneity. Although this kind of modelling is widely used on basin scale in exploration geology, its application on field scale in production geology is virtually non-existent. We have assessed whether the recent developments in numerical modelling can also aid petroleum geologists in the interpretation of the reservoir geology.Seismic data, well data and a process-response model for coastal environments were used to characterise the Lower Cretaceous oil-bearing Rijn Field. Interpretation of seismic and well data led to a definition of the structural setting and the depositional model of the Rijn Member in the area. From the sedimentological interpretation the sea-level history could be estimated, which is the one of the most important input parameters for the process-response model.Application of the process-response simulator to the Rijn Field resulted in approval of the depositional model. The output was presented in a 2-dimensional north-south profile, which corresponds very well to the well logs along this section. The results demonstrate that numerical simulations of geological processes can be very useful as a tool to explore many likely geological scenarios. While it cannot be used to supply a unique solution in many cases, it forms a helpful guide during reservoir characterisation to find an optimal scenario of the controls on deposition of the Rijn Member, which contributes to the understanding of the inter-well reservoir heterogeneity.

Porosity from seismic data: A geostatistical approach

Geophysics ◽  
1988 ◽  
Vol 53 (10) ◽  
pp. 1263-1275 ◽  
Author(s):  
Philippe M. Doyen
Keyword(s):  
Seismic Data ◽  
Mean Square ◽  
Least Squares Regression ◽  
Reservoir Properties ◽  
Reflection Seismic ◽  
Geostatistical Approach ◽  
Independent Observations ◽  
Local Correlations ◽  
Mapping Techniques ◽  
Well Data

Using a geostatistical technique called cokriging, the areal distribution of porosity is estimated first in a numerically simulated reservoir model, then in an oil‐bearing channel‐sand of Alberta, Canada. The cokriging method consistently integrates 3-D reflection seismic data with well measurements of the porosity and provides error‐qualified, linear mean square estimates of this parameter. In contrast to traditional seismically assisted porosity mapping techniques that treat the data as spatially independent observations, the geostatistical approach uses spatial autocorrelation and crosscorrelation functions to model the lateral variations of the reservoir properties. In the simulated model, the experimental root‐mean square porosity error with cokriging is 50 percent smaller than the error in predictions relying on a least‐squares regression of porosity on seismically derived transit time in the reservoir interval. In the Alberta reservoir, a cross‐validation study at the wells demonstrates that the cokriging procedure is 20 percent more accurate, in a mean square sense, than a standard regression method, which accounts only for local correlations between porosity and seismically derived impedances. In both cases, cokriging capitalizes on areally dense seismic measurements that are indirectly related to porosity. As a result, when compared to estimates obtained by interpolating the well data, this technique considerably improves the spatial description of porosity in areas of sparse well control.

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