THE APPLICATION OF 3D SEISMIC INTERPRETATION TECHNIQUES FOR OPTIMISING WELL PLACEMENT: FORTESCUE FIELD RE DEVELOPMENT, GIPPSLAND BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 31
Author(s):  
P.J. Ryan ◽  
T.E. Vinson
Keyword(s):  
High Precision ◽  
Seismic Data ◽  
Development Program ◽  
Seismic Interpretation ◽  
3D Seismic ◽  
Well Placement ◽  
Seismic Waveform ◽  
Attribute Analysis ◽  
Definition Of ◽  
Gippsland Basin

In order to achieve successful drilling results on mature fields, geophysical analysis has become increasingly focussed on the application of high precision 3D seismic interpretation and analysis techniques. These techniques were critical to the success of the re-development program recently completed on the Fortescue Field* Gippsland Basin. Fortescue, initially developed in 1983, contains an estimated oil reserve of 300 million barrels. The field is currently over 80 percent depleted. To offset declining production and develop remaining reserves, an 18 well additional drilling program together with upgrades to platform topsides and production facilities was conducted on the field from October 1994 to October 1996.Many of the proposed additional drilling opportunities relied on oil being trapped structurally updip from existing completions. Given the size (approx. 1 MSTB) and subtle, low relief nature of the targets being pursued, the precision of conventional 3D seismic interpretation techniques was inadequate to optimise the location of wells. This necessitated the development of a series of specific tools that could provide high resolution definition of both the trap and lithology as well as optimising well placement.These high precision interpretation techniques include: reservoir subcrop edge prediction through qualitative calibration of geological models to seismic data: the assessment of overburden velocity distortions of the seismic time field by utilising isochron mapping and interval attribute analysis; and prediction of trap geometries and lateral stratigraphic variations by the application of seismic waveform attributes.The application of these advanced 3D seismic interpretation techniques and their integration with related geoscience and engineering technologies resulted in the completion of a successful 18 well re-development program for the Fortescue field.

scholarly journals A new depositional model for the Tuaheni Landslide Complex, Hikurangi Margin, New Zealand

2020 ◽  
Vol 500 (1) ◽  
pp. 551-566 ◽  
Author(s):  
Benjamin Couvin ◽  
Aggeliki Georgiopoulou ◽  
Joshu J. Mountjoy ◽  
Lawrence Amy ◽  
Gareth J. Crutchley ◽  
...  
Keyword(s):  
Seismic Data ◽  
Lateral Spreading ◽  
3D Seismic ◽  
Depositional Processes ◽  
Attribute Analysis ◽  
Internal Structures ◽  
Show Evidence ◽  
Levee System ◽  
Central Ridge ◽  
International Ocean Discovery Program

AbstractThe Tuaheni Landslide Complex (TLC) is characterized by areas of compression upslope and extension downslope. It has been thought to consist of a stack of two genetically linked landslide units identified from seismic data. We used 3D seismic reflection, bathymetry data and International Ocean Discovery Program Core U1517C (Expedition 372) to understand the internal structures, deformation mechanisms and depositional processes of the TLC deposits. Units II and III of U1517C correspond to the two chaotic units in 3D seismic data. In the core, Unit II shows deformation, whereas Unit III appears more like an in situ sequence. Variance attribute analysis showed that Unit II is split into lobes around a coherent stratified central ridge and is bounded by scarps. By contrast, we found that Unit III is continuous beneath the central ridge and has an upslope geometry, which we interpreted as a channel–levee system. Both units show evidence of lateral spreading due to the presence of the Tuaheni Canyon removing support from the toe. Our results suggest that Units II and III are not genetically linked, are separated substantially in time and had different emplacement mechanisms, but they fail under similar circumstances.

THE INTEGRATION OF MODERN TECHNOLOGY IN GIPPSLAND'S CENTRAL FIELDS STUDY

1994 ◽  
Vol 34 (1) ◽  
pp. 513
Author(s):  
P.V.Hinton P.V.Hinton ◽  
M.G.Cousins ◽  
P.E.Symes
Keyword(s):  
Seismic Data ◽  
Field Performance ◽  
Simulation Models ◽  
Modern Technology ◽  
Depositional Environments ◽  
Seismic Attribute ◽  
Sequence Stratigraphic ◽  
Multidisciplinary Study ◽  
Attribute Analysis ◽  
Definition Of

The central fields area of the Gippsland Basin, Australia, includes the Halibut, Cobia, Fortescue, and Mackerel oil fields. These large fields are mature with about 80% of the reserves produced. During 1991 and 1992 a multidisciplinary study, integrating the latest technology, was completed to help optimise the depletion of the remaining significant reserves.A grid of 4500 km of high resolution 3D seismic data covering 191 square kilometres allowed the identification of subtle structural traps as well as better definition of sandstone truncation edges which represent the ultimate drainage points. In addition, the latest techniques in seismic attribute analysis provided insight into depositional environments, seal potential and facies distribution. Sequence stratigraphic concepts were used in combination with seismic data to build complex multi million cell 3D geological models. Reservoir simulation models were then constructed to history match past production and to predict future field performance. Facility studies were also undertaken to optimise depletion strategies.The Central Fields Depletion Study has resulted in recommendations to further develop the fields with about 80 work-overs, 50 infill wells, reduction in separator pressures, and gas lift and water handling facility upgrades. These activities are expected to increase ultimate reserves and production. Some of the recommendations have been implemented with initial results of additional drilling on Mackerel increasing platform production from 22,000 BOPD to over 50,000 BOPD. An ongoing program of additional drilling from the four platforms is expected to continue for several years.

THE YELLOWTAIL OIL DISCOVERY

1983 ◽  
Vol 23 (1) ◽  
pp. 170
Author(s):  
A. R. Limbert ◽  
P. N. Glenton ◽  
J. Volaric
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
3D Seismic ◽  
Well Control ◽  
Reservoir Volume ◽  
3D Data ◽  
Small Feature ◽  
Gippsland Basin

The Esso/Hematite Yellowtall oil discovery is located about 80 km offshore in the Gippsland Basin. It is a small accumulation situated between the Mackerel and Kingfish oilfields. The oil is contained in Paleocene Latrobe Group sandstones, and sealed by the calcareous shales and siltstones of the Oligocene to Miocene Lakes Entrance Formation. Structural movement and erosion have combined to produce a low relief closure on the unconformity surface at the top of the Latrobe Group.The discovery well, Yellowtail-1, was the culmination of an exploration programme initiated during the early 1970's. The early work involved the recording and interpretation of conventional seismic data and resulted in the drilling of Opah- 1 in 1977. Opah-1 failed to intersect reservoir- quality sediments within the interpreted limits of closure although oil indications were encountered in a non-net interval immediately below the top of the Latrobe Group. In 1980 the South Mackerel 3D seismic survey was recorded. The interpretation of these 3D data in conjunction with the existing well control resulted in the drilling of Yellowtail-1 and subsequently led to the drilling of Yellowtail-2.In spite of the intensive exploration to which this small feature has been subjected, the potential for its development remains uncertain. Technical factors which affect the viability of a Yellowtail development are:The low relief of the closure makes the reservoir volume highly sensitive to depth conversion of the seismic data.The complicated velocity field makes precise depth conversion difficult.The thin oil column reduces oil recovery efficiency.The detailed pattern of erosion at the top of the Latrobe Group may be beyond the resolution capability of 3D seismic data.The 3D seismic data may not be capable of defining the distribution of the non-net intervals within the trap.The large anticlinal closures and topographic highs in the Gippsland Basin have been drilled, and the prospects that remain are generally small or high risk. Such exploration demands higher technology in the exploration stage and more wells to define the discoveries, and has no guarantee of success. The Yellowtail discovery is an illustration of one such prospect that the Esso/Hematite joint venture is evaluating.

Imposing interpretational constraints on a seismic interpretation CNN

Geophysics ◽  
2021 ◽  
pp. 1-36
Author(s):  
Haibin Di ◽  
Cen Li ◽  
Stewart Smith ◽  
Zhun Li ◽  
Aria Abubakar
Keyword(s):  
Seismic Data ◽  
Recent Progress ◽  
Facies Analysis ◽  
Three Dimensional ◽  
Seismic Interpretation ◽  
3D Seismic ◽  
Geologic Time ◽  
Seismic Amplitude ◽  
Subsurface Geology ◽  
3D Seismic Data

With the expanding size of three-dimensional (3D) seismic data, manual seismic interpretation becomes time consuming and labor intensive. For automating this process, the recent progress in machine learning, particularly the convolutional neural networks (CNNs), has been introduced into the seismic community and successfully implemented for interpreting seismic structural and stratigraphic features. In principle, such automation aims at mimicking the intelligence of experienced seismic interpreters to annotate subsurface geology both accurately and efficiently. However, most of the implementations and applications are relatively simple in their CNN architectures, which primary rely on the seismic amplitude but undesirably fail to fully use the pre-known geologic knowledge and/or solid interpretational rules of an experienced interpreter who works on the same task. A general applicable framework is proposed for integrating a seismic interpretation CNN with such commonly-used knowledge and rules as constraints. Three example use cases, including relative geologic time-guided facies analysis, layer-customized fault detection, and fault-oriented stratigraphy mapping, are provided for both illustrating how one or more constraints can be technically imposed and demonstrating what added values such a constrained CNN can bring. It is concluded that the imposition of interpretational constraints is capable of improving CNN-assisted seismic interpretation and better assisting the tasks of subsurface mapping and modeling.

Recognition and characterization of small-scale sand injectites in seismic data: Implications for reservoir development

2021 ◽  
pp. jgs2021-041
Author(s):  
Alma Dzozlic Bradaric ◽  
Trond Andersen ◽  
Isabelle Lecomte ◽  
Helge Løseth ◽  
Christian Haug Eide
Keyword(s):  
Seismic Data ◽  
Small Scale ◽  
3D Seismic ◽  
Well Placement ◽  
Reflection Seismic ◽  
Seismic Modelling ◽  
Link Type ◽  
Reservoir Development ◽  
Net To Gross ◽  
Seismic Images

Small-scale (< 20 m), non-resolvable sand injectites can constitute a large part of the net-to-gross volume and affect fluid flow in the reservoir. However, they may also cause challenges for well placement and reservoir development because they are too small to be reliably constrained by reflection seismic data. It is therefore important to better understand how small-scale injectites influence seismic images and may be recognized and characterized above reservoirs. The Grane Field (North Sea) hosts numerous small-scale sand injectites above the main reservoir unit, causing challenges for well placement, volume estimates and seismic interpretation. Here, we investigate how such small-scale sand injectites influence seismic images and may be characterized by (1) using well-, 3D seismic- and outcrop data to investigate geometries of small-scale sand injectites (0-15 m) and creating conceptual models of injectite geometries, (2) performing seismic convolution modelling to investigate how these would be imaged in seismic data, and (3) compare these synthetic seismic images to actual 3D seismic from the well-investigate Grane Field.Our results show that despite injectites being below seismic resolution, small-scale sand injectites can be detected in seismic data. They are more likely to be detected with high thickness (> 5 m), steep dip (> 30°), densely spaced sand injectites, and homogeneous background stratigraphy. Furthermore, as fraction of sand injectites increases the top reservoir amplitude will decrease. Moreover, comparison of the synthetic seismic images with real seismic data from the Grane Field indicates that the low-amplitude anomalies and irregularities observed above the reservoir may be a result of the overlying sand injectites. Additionally, the comparison strongly suggests that the Grane Field hosts sand injectites that are thicker and located further away from the top reservoir than what is indicated by well observations. These results may be used to improve well planning and develop reservoirs with overlying sand injectites.Supplementary material: A PDF file containing all the seismic modelling results allowing the reader to flip back and forth between the different models is available at https://www.doi.org/10.6084/m9.figshare.14333102 . Well logs from well 25/11-18 T2 are available at https://factpages.npd.no/pbl/wellbore_documents/2358_25_1_18_COMPLETION_REPORT_AND_LOG.pdf

Identification of polygonal faulting from legacy 3D seismic data in vintage Gulf of Mexico data using seismic attributes

2021 ◽  
pp. 1-17
Author(s):  
Karen M. Leopoldino Oliveira ◽  
Heather Bedle ◽  
Karelia La Marca Molina
Keyword(s):  
Seismic Data ◽  
Seismic Attributes ◽  
Fault System ◽  
3D Seismic ◽  
Seismic Attribute ◽  
Variable Amplitude ◽  
Attribute Analysis ◽  
Amplitude Data ◽  
3D Seismic Data ◽  
Polygonal Fault

We analyzed a 1991 3D seismic data located offshore Florida and applied seismic attribute analysis to identify geological structures. Initially, the seismic data appears to have a high signal-to-noise-ratio, being of an older vintage of quality, and appears to reveal variable amplitude subparallel horizons. Additional geophysical analysis, including seismic attribute analysis, reveals that the data has excessive denoising, and that the continuous features are actually a network of polygonal faults. The polygonal faults were identified in two tiers using variance, curvature, dip magnitude, and dip azimuth seismic attributes. Inline and crossline sections show continuous reflectors with a noisy appearance, where the polygonal faults are suppressed. In the variance time slices, the polygonal fault system forms a complex network that is not clearly imaged in the seismic amplitude data. The patterns of polygonal fault systems in this legacy dataset are compared to more recently acquired 3D seismic data from Australia and New Zealand. It is relevant to emphasize the importance of seismic attribute analysis to improve accuracy of interpretations, and also to not dismiss older seismic data that has low accurate imaging, as the variable amplitude subparallel horizons might have a geologic origin.

Space-time continuum in seismic stratigraphy: Principles and norms

2018 ◽  
Vol 6 (1) ◽  
pp. T97-T108 ◽  
Author(s):  
Farrukh Qayyum ◽  
Christian Betzler ◽  
Octavian Catuneanu
Keyword(s):  
Seismic Data ◽  
Seismic Stratigraphy ◽  
Seismic Interpretation ◽  
Space Time ◽  
Practical Significance ◽  
3D Seismic ◽  
Close Link ◽  
Time Continuum ◽  
3D Seismic Data ◽  
Stratigraphic Succession

Seismic stratigraphy is not only a geometric understanding of a stratigraphic succession, but it also has a close link to the space-time continuum started by H. E. Wheeler (1907–1987). The science follows the fundamental principles of stratigraphy, and the norms that govern seismic interpretation play a fundamental role due to their practical significance. The birth of computer-aided algorithms paved a new platform for seismic interpretation. The ideas from A. W. Grabau (1870–1946) and Wheeler were brought to a new level when space-time continuum was represented using 3D seismic data. This representation is commonly referred to as the Wheeler transformation, and it is based on flattening theories. Numerous algorithms have been introduced. Each suffers from its own problem and follow some assumption. The hydrocarbon industry, as well as academia, should seek a solution that is globally applicable to a stratigraphic succession irrespective of resolution, geologic challenges, and depositional settings. We have developed a review of the principles and norms behind these algorithms assisting in developing the space-time continuum of a stratigraphic succession using 2D/3D seismic data.

Quantitative application of post-stack inversion of organic-rich shale based on rock physics linear relationship and 3D seismic data, Perth Basin, Western Australia

2014 ◽  
Vol 54 (2) ◽  
pp. 532
Author(s):  
Yazeed Altowairqi ◽  
Reza Rezaee ◽  
Milovan Urosevic
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Rock Physics ◽  
Seismic Inversion ◽  
3D Seismic ◽  
Physical Relationship ◽  
Seismic Properties ◽  
Attribute Analysis ◽  
Exploration And Production ◽  
Compressional Velocity

Unconventional resources such as shale gas have been an extremely important exploration and production target. To understand the seismic responses of the shale gas plays, the use of rock physical relationship is important, which is constrained with geology and formation-evaluation analysis. Since organic-rich shale seismic properties remains poorly understood, seismic inversion can be used to identify the organic-rich shale from barren shale. This approach helps identify and map spatial distributions and of the organic rich shales. This study shows the acoustic impedance (AI), which is the product of compressional velocity and density, decreases nonlinearly with increasing total organic carbon (TOC) content. TOC is obtained using Roc-Eval pyrolysis for more than 120 core shale samples for the Perth Basin. By converting the AI data to TOC precent on the seismic data, we therefore can map lateral distribution, thickness, and variation in TOC profile. This extended abstract presents a case study of the northern Perth Basin 3D seismic with application of different approaches of seismic inversion and multi-attribute analysis with the rock physical relationships.

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