Interpretation Of 3D Seismic Data Research Articles

Outer-Bank Bars: A New Intra-Channel Architectural Element within Sinuous Submarine Slope Channels

Abstract This study describes for the first time “outer-bank bars,” an intra-channel architectural element that is unique to sinuous submarine channels. The study is based on interpretation of 3D seismic data of sinuous channels in the upper slope of the Amazon Fan, offshore Brazil. Outer-bank bars comprise channel-fill deposits found in tight meander loops at outer corners of bend apices or slightly upstream or downstream of apices. This architectural element can be up to 1.5 km wide and up to 150 m thick with continuous internal reflectors dipping 1–20° towards the inner bend of the meander loop, a direction of dip opposed to that of fluvial point bars or submarine lateral-accretion packages. The angles of outer-bank bar surfaces increased to a maximum at bend apices. Outer-bank bars occur in the final aggradational channel fill in the two separated channel–levee systems in the Amazon data set. They may have been formed as a result of enhanced deposition on the outside of the bend caused by a combination of flow-volume reduction and flow superelevation. Accretion of outer-bank bars may cause the thalweg position to shift towards the inner bends leading to sinuosity reduction. Since this architectural element is likely to be sand prone, its recognition may have significant implications for prediction of hydrocarbon reservoirs.

Using empirical geological rules to reduce structural uncertainty in seismic interpretation of faults

Good seismic interpretation of faults should include a workflow that checks the interpretation against known structural properties of fault systems. Estimates of wall-rock strains provide one objective means for discriminating between correct and incorrect structural interpretations of 2D and 3D seismic data – implied wall-rock strain should be below a geologically plausible maximum. We call this the strain minimisation approach. Drawing on the large body of published data for strike dimension and maximum displacement for faults we suggest a realistic upper limit of wall-rock shear strain of 0.05, and 0.1 for maximum longitudinal strain when measured in the displacement direction. Small-scale variation of fault wall-rock strain also adheres to this rule, except in specific areas of strain localisation such as relay zones. As a case study we review an existing structural interpretation of 2D seismic surveys. Mapping of shear and longitudinal strain on the fault planes show values commonly greater than 0.05 and 0.1 respectively. Thus the model is deemed inadmissible. We then reinterpreted the area in an iterative manner using the strain minimisation approach. By using regions of implied high wall-rock strain as an indicator of high uncertainty in the interpretation, we were able to break out two self-consistent fault sets, each of which had geologically plausible wall-rock strains, where previously there had only been one fault set with highly implausible wall-rock strains.

Detecting stratigraphic features via crossplotting of seismic discontinuity attributes and their volume visualization

Over the last decade, our industry has witnessed steadily increasing computer power, core memory, peripheral storage, and advanced display technology, as well as development of commercial software backed by dedicated research efforts. These developments have lead to a moderate acceptance of volume interpretation of 3D seismic data by the geoscience community. 3D volume rendering is one form of visualization that involves opacity control to view the features of interest “inside” the 3D volume. A judicious choice of opacity applied to edge-sensitive attribute subvolumes, such as curvature or coherence, corendered with the seismic amplitude volume can both accelerate and lend confidence to the interpretation of complex structure and stratigraphy.

Formation and types of natural gas reservoirs of the Tangyuan fault depression in Yi-Shu graben

Abstract Based on drilling, logging and geochemical data from 32 wells, the depositional and tectonic evolution of the Tangyuan fault depression were studied and the gas accumulation conditions and gas reservoir types were analyzed. Based on interpretation of 2D and 3D seismic data, a structure map of each layer was plotted and the trap types developed in various structural layers were found and confirmed. The source rock of the Tangyuan fault depression was mainly developed in the Cretaceous and in the Eogene Wuyun Formation, Xin'ancun Formation, Dalianhe Formation Member 1 and Baoquanling Formation Member 1. The reservoirs are of similar age and include the Eogene Wuyun Formation, Xin'ancun Formation, Dalianhe Member 2 and Baoquanling Member 2. The caprock was developed in the Dalianhe and Baoquanling Member 1. There are three types of source-reservoir-caprock assemblages present which include self-generating & self-preserving, lower-generating & upper-preserving and new-bed-generating & old-bed-preserving. Drilling has demonstrated that there are two types of gas reservoirs, a composition lithologic-structural gas reservoir and a lithologic gas reservoir. With reference to the seismic data and known reservoir data in adjacent areas, it is estimated that there may also be structural gas reservoirs and stratigraphic gas reservoirs.

Back-stripped 3D seismic data: A new tool applied to testing sill emplacement models

ABSTRACT It is common practice for geological studies based on interpretation of 3D seismic data to utilize two-way time datasets for convenience. Even depth-imaged or depth-converted 3D datasets have limitations if palaeogeometries are important in understanding the geological process under investigation. In this study I introduce the production of a back-stripped 3D seismic cube to allow examination of restored geometries and depths, which requires time-to-depth conversion and 3D back-stripping. For both processes, either standard functions or more complex models can be utilized as merited. To illustrate the method, I have produced a back-stripped 3D seismic cube across a saucer-shaped igneous intrusion. The sill9s restored original geometry fits recent observational and experimental intrusion models, with some modification. Magma supply appears to have been to a deep off-centre point within the inner sill, 3000 m below palaeosurface, with a possible contribution to a more peripheral feeder system below the inclined sheet, and magma propagation to the outer sill being outwards and upwards. The value of a back-stripped 3D seismic cube is not limited to studies of igneous intrusions, but may have application in many areas of subsurface sedimentary basin studies, such as fluid migration path modelling and evolution of hydrocarbon trap geometries.

Gumusut-Kakap Project: Geohazard Characterization and Effect on Field Development

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12554, "Gumusut-Kakap Project: Geohazard Characterisation and Impact on Field- Development Plans," by C. Hadley, D. Peters, and A. Vaughan, SPE, Shell International E&P, and D. Bean, Sarawak Shell Sdn. Bhd., originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. Shell and venture partners encountered numerous seafloor and near-seafloor geohazards at the deepwater Gumusut-Kakap field on the continental slope offshore Malaysia. Early identification of the geohazards, by interpretation of exploration 3D-seismic data and evaluation of discovery and appraisal-well logs, provided the impetus necessary to undertake an extensive data-acquisition program to determine the extent of the hazards and the mitigation needed for a successful development. Introduction The Gumusut-Kakap field in the Malaysian deepwater province offshore northwest Borneo was discovered in 2003 with the drilling of the Gumusut-1B well. The field is 120 km offshore, in the southern portion of Sabah Block J and Block K. Four appraisal wells, Gumusut-2 and Gumusut-3 in Block J and Kakap-1 and Kakap-2 in Block K, were drilled during 2004–05. The seafloor slopes regionally to the southwest, with a gradient of approximately 5°, and water depths within the development area vary from 900 to 1200 m. Seafloor and near-seafloor sediments are hemipelagic, interbedded with turbidites and mass-transport deposits (MTDs). Exploration 3D-seismic data and data from the discovery and appraisal wells were interpreted in 2005 to identify geohazards that could influence field-development plans and to screen potential surface well locations. The seafloor extraction from the 3D-seismic data set revealed a variable seafloor topography. The most prominent topographic features are a series of upper-slope canyons, which are interpreted to be the seafloor expression of buried mass-transport complexes and a steep-sided seafloor bulge. The bulge rises 120 to 150 m above the surrounding seafloor and is approximately 8 km wide. The bulge is the surface expression of one of a series of deep-seated anticlines, which are common in the region. Both flanks of the bulge have been eroded by downslope mass failures. Appraisal wells Gumusut-2, Kakap-1, and Kakap-2 were drilled on the bulge. Anomalies in the subsurface data included a bottom-simulating reflector (BSR) between 150 and 180 m below the seafloor, which underlies the downdip portion of the bulge and coincides with an extensive seismic wipeout zone.

Reducing structural uncertainty in seismic interpretation by mapping wall-rock strains to get a plausible geological model - the strain minimisation approach

Estimates of wall-rock strains provide an objective means for discriminating between correct and incorrect structural interpretations of 2D and 3D seismic data. Good interpretation of faults should include a workflow that checks and keeps wall-rock strain below a geologically plausible maximum. We call this the strain minimisation approach.

Crustal structure of the deepwater west Niger Delta passive margin from the interpretation of seismic reflection data

The interpretation of 2D and 3D seismic reflection data complemented with gravity data allows the crustal architecture of the deepwater west Niger Delta passive margin to be defined. The data show that the area is underlain by oceanic crust that is characterised by a thickness of 5–7 km and by internal reflectivity consisting of both dipping and sub-horizontal reflectors. Some of the dipping reflections can be traced up to the top of the basement where they offset it across a series of minor to major thrust faults. Other internal reflections are attributed to extensional shear zones and possibly due to intrusions in the lower crust. The Moho can be correlated as a discrete reflection over >70% of the study area. It is generally smooth, but localised relief of up to 1 km is observed. The southeastern part of the study area is dominated by a zone of SW–NE striking basement thrusts. The crustal thickness in the study area is below the global average for a typical oceanic crust. Generally the crust is thinnest around a major transform structure, the Chain Fracture Zone, possibly related to the local geometry of the spreading fabrics. There is no significant variation in the thickness of the crust across this ocean–ocean transform in the area. The recognition of oceanic crust has profound implications for heat flow and thermal maturation of hydrocarbons in the Niger Delta petroleum province.

Enhanced compartmentalization of a complex reservoir with sub-seismic faults from geological inversion

Sealing faults are fundamental for delimitation of compartments in a reservoir and they are usually identified by geological interpretation of 3D seismic data which are limited to the resolution of seismic sections. Dynamic production data may suggest in some cases the existence of smaller faults or vertical discontinuities which may not be detected from seismic. It is reasonable to assume that, with increasing resolution of 3D seismic, large faults could be accurately identified while faults with strike slip or small throw may remain invisible to seismic. This paper proposes a geological inversion approach for modeling sub-seismic vertical discontinuities or faults using dynamic data. The methodology is based on a prior self-similar generation of faults which are geometrically downscaled from larger faults interpreted from seismic. Then, the approach follows an iterative inverse Gauss–Newton modeling technique to update fault size and location parameters based on the reservoir pressure response. The convergence criteria include comparing both the observed and model calculated shut-in bottom-hole pressure (SBHP) and flowing well head pressure (FWHP) until the squared differences between the observed and model calculated pressures diminish to a minimum. If the convergence criteria were not met, the fault pattern is modified and the geocellular grid is cut with updated faults to generate a new version of the faulted simulation model for the next iteration. As an alternative, commercial assisted history match (AHM) software can be utilized to expressively adjust fault locations in the simulation model to match the production history; however, such perturbations are not done at the geological level as in the proposed approach. Thus, the approach in this paper has the advantage of preserving the spatial and geological integrity of the geocellular model. In addition, the spatial consistency between the geological and simulation models is always guaranteed in the proposed approach.

Comment on: Determining magma flow in sills, dykes and laccoliths and their implications for sill emplacement mechanisms by Ken Thomson [Bulletin of Volcanology 70: 183–210

Thomson (2007) “demonstrate[d] that...upwards and outwards branching magma flow networks are common to all doleritic sills intruded into sedimentary sequences”. This statement stemmed from interpretation and visualisation of 3D seismic data to constrain magma flow patterns in sills, dykes and laccoliths in the Flett Basin, part of the UK sector of the Faroe-Shetland Basin. The data quality is excellent, and seismic reflector geometries are compelling: radiating sill branches and lobes, and clear spatial relationships between dykes, sills and contemporaneous surface fissures. The resulting model proposed for the emplacement of radially symmetric sills starts with the spreading of the inner saucer from a central feeder, then climbing of magma tubes which may subsequently merge into an inclined sheet, followed by development of a relatively concordant outer rim. Thomson (2007) also discussed the preferential intrusion of magma into shale-prone host rock, the “properties [of which are] the dominant control that permits magma intrusion along such horizons regardless of their proximity to the level of neutral buoyancy”. His observations from the Flett Basin area, together with those from the northeast Rockall Trough (Thomson and Hutton 2004), exemplified the sill intrusion process to the point that allowed the generalisation “the basic features of laccolith emplacement also apply to all doleritic sills in such settings”. While the interpretation of the Flett Basin dataset seems unequivocal, I would suggest that the generality of both the proposed intrusion emplacement mechanism and preferred lithology is open to debate, and additional factors such as local porosity and stress regime may play additional important roles in controlling intrusion emplacement mechanism. Thomson’s vision for this field of research was the defining of tools and techniques, and the publishing of striking case studies. He thereby set the stage for further work into a developing understanding of igneous intrusion processes via interrogation of 3D seismic datasets.

Glacially influenced petroleum plays in the Kulshill Group (Late Carboniferous–Early Permian) of the Southeastern Bonaparte Basin, Western Australia

Glacial deposits within the Lower Kulshill Group (Late Carboniferous-Early Permian) were initially recognised in cores from onshore wells in the southeastern Bonaparte Basin in the 1960s. Subsequent offshore wells have extended the distribution of the glaciogene units 100 km to the north. Their capacity to entrap oil and gas was proven by the Turtle and Barnett wells, located on the offshore Turtle High. Similar age glaciogene rocks occur within the Cooper Basin of central Australia, where they contain oil and gas reserves, and in the Canning, Carnarvon and Perth basins of Western Australia. Using sparse cores, electric logs, palynology and a sequence stratigraphic interpretation of 2D seismic data, the distribution of potential reservoir sandstones and sealing lithologies of the glaciogenic strata has been mapped for the offshore southeastern Bonaparte Basin. This study highlights the petroleum trapping potential associated with sub-glacial ice tunnel valley features, which are widespread in the offshore part of the basin.

Influence of pre-salt alignments in post-Aptian magmatism in the Cabo Frio High and its surroundings, Santos and Campos basins, SE Brazil: An example of non-plume-related magmatism

This study, based on interpretations of 2D and 3D seismic data, onshore satellite data, and offshore seismic mapping and well data, addresses the geological evolution of Late Cretaceous and Early Tertiary magmatism in the offshore Cabo Frio area, at the border between the Santos and Campos basins, SE Brazil. The analysis of the available data set suggests an alternative genesis for this magmatism, different from the classic mantle plume model. Seismic mapping of the main feeder dikes reveals a predominant SE–NW orientation, coincident with the alignment of the Cruzeiro do Sul deformation zone, in which the Cabo Frio High is included. This observation is coherent with the characteristics of the major onshore Precambrian strike-slip faults, which were reactivated during the Cenozoic. The largest offshore volumes of magmatic rocks occur intercalated in the sedimentary section and at the intersections of two fault alignments: a SE–NW, strike-slip fault trend and a SW–NE, normal fault trend, similar to the onshore alkaline bodies of the Poços de Caldas–Cabo Frio alignment. The possibly reactivated faults (mainly SE–NW transfer faults) could have cut through the whole lithosphere, reached the asthenosphere, and caused partial melting simply by pressure release.

Uncertainties in Seismic Facies Analysis for Reservoir Characterisation or Monitoring: Causes and Consequences

Multivariate probabilistic pattern recognition methods such as discriminant analysis are powerful for interpreting seismic data in terms of reservoir properties. They consist of calibrating a mathematical relationship between local seismic information (seismic voxels or pieces of traces extracted at a reservoir level), characterised by a set of measurements, named seismic attributes, and a pre-defined set of classes, named seismic facies. In the context of seismic reservoir characterisation, this methodology provides a map or a volume of most probable facies, which describes the main reservoir heterogeneities. During the last decade, another application of this technique to the interpretation of 4D seismic data has also emerged: in this case, each seismic vintage is interpreted in terms of seismic facies, and differences in the interpretation of one vintage from another are correlated a posteriori to production effects such as fluid substitutions or pressure variations. As a probabilistic method, discriminant analysis allows the evaluation, at least partly, of uncertainty associated with seismic facies interpretation, and assignment probabilities computed by the methodology are a measure of the confidence of the interpretation. However, this uncertainty evaluation is only partial. In this paper, we will describe three other aspects of uncertainties, which are not correctly handled by classical discriminant analysis. The first aspect is linked with measurement errors. To propagate this type of error in seismic facies analysis, we have had to develop a methodology based on a combination of discriminant analysis and interval analysis. The other two aspects of uncertainty are linked with the interpretation of seismic facies. Due to the difference in resolution between seismic data in real reservoir heterogeneities, one seismic facies may correspond to several different fine-scale geological or dynamic scenarios. We will show in this paper how pseudo-well methodology, as well as seismic modelling (in the context of 4D interpretation) can help address this issue.

Fusion of 3D seismic exploration and seafloor geochemical survey for methane hydrate exploration

The MH21 Research Consortium has conducted a high-resolution 3D seismic survey and a seafloor geochemical survey, to explore methane hydrate reservoirs in the eastern Nankai Trough, offshore Japan. Excellent geological information about shallow formations was obtained from the high-resolution 3D seismic survey, which was designed to image the shallow formations where methane hydrates exist. The information is useful in constructing a geological and geochemical model, and especially to understand the complex geology of seafloor, including geochemical manifestations and the structure of migration conduits for methane gas or methane-bearing fluid.By comparing methane seep sites observed by submersibles with seismic sections, some significant relationships between methane hydrate reservoirs, free gas accumulations below the seafloor, and seafloor manifestations are recognised. Bathymetric charts and seafloor reflection amplitude maps, constructed from seismic reflections from the seafloor, are also useful in understanding the relationships over a vast area. A new geochemical seafloor survey targeted by these maps is required.The relationships between methane hydrate reservoirs and seafloor manifestations are becoming clearer from interpretation of high-resolution 3D seismic data. The MH21 Research Consortium will continue to conduct seafloor geochemical surveys based on the geological and geochemical model constructed from high-resolution 3D seismic data analysis.In this paper, we introduce a basis for exploration of methane hydrate reservoirs in Japan by fusion of 3D seismic exploration and seafloor geochemical surveys.

Controls on the basinwide architecture of late Miocene (Messinian) evaporites on the Levant margin (Eastern Mediterranean)

Interpretation of 2D and 3D seismic data from the Levant margin (Eastern Mediterranean) has revealed the complex depositional and structural setting of the basinwide late Miocene (Messinian) evaporites. The data set covers a total area of 20,000 km 2, permitting a semi-regional investigation of the thick (up to 1.8 km) evaporitic wedge. The sequential analysis of time–structure maps, isochron maps and seismic cross-sections highlighted the main morphological and structural features characterizing the pre-, syn- and post-evaporitic Levant margin. This approach provided insights on the impact of local vs. regional factors in governing the distribution of the Messinian Salinity Crisis in the region. Two regional features have been recognized as the most significant controlling factors for the architecture of the Messinian evaporites. Firstly, a series of anticlines of the Syrian Arc foldbelt acted as a structural barrier indirectly governing the overall landward extension of the evaporites. Secondly, submarine canyons active in the area at least since the Oligocene (Afiq, El Arish and Ashdod Canyons) represented preferential sites of erosion and deposition of evaporites. Our results document therefore the importance of the deep-seated structures and relict drainage for the architecture of the Messinian evaporites on the Levant margin. The new insights provided can be additionally used to infer the original depositional geometry of the evaporites in the study area and as an analogue in other Mediterranean areas where 3D seismic is not available yet and sub-salt imaging is limited.

Cluster visualization rises to the seismic processing challenge

Abstract Phil Hodgson, Chris Cunnell, Alex Krueger and Andy MacGregor describe how processing and interpretation of 3D seismic data has been transformed by the emergence of cluster-based visualization.

Role of Cenozoic fault reactivation in controlling pre-rift plays, and the recognition of Zechstein Group evaporite-carbonate lateral facies transitions in the East Orkney and Dutch Bank basins, East Shetland Platform, UK North Sea

The East Orkney and Dutch Bank basins are located to the north of the Moray Firth rift arm in the UK North Sea. The East Orkney Basin measures approximately 60 by 30 km and is bounded to the west, north and east by large normal faults. The West Fladen High consists of a series of horsts and grabens, and separates the East Orkney Basin from the Dutch Bank Basin, which is situated immediately to the north of the Witch Ground Graben and to the west of the Fladen Ground Spur. Although exploration well results for the limited penetrations of structural highs on the margins of the East Orkney Basin have been disappointing, geophysical and geochemical analyses all appear to indicate the presence of a mature source in the region. Integration of wireline data, core samples, and the interpretation of 2D seismic data within the area allow mapping of the main structures in the basins and correlation to the adjacent well penetrations, thus not only enabling a tectonic and stratigraphic history, but also a framework for prospectivity to be established. A pillow-shaped sedimentary package at approximately 3 seconds two-way traveltime within the centre of the East Orkney Basin represents the downdip equivalent of stratigraphy on the West Fladen High, and is interpreted to be a Zechstein Group salt body, underlain by a thick sequence of Lower Permian (Rotliegend Group) and Devonian strata. Cored intervals from well 14/2-1 on the West Fladen High contain carbonates, evaporite dissolution breccias and anhydrites, implying a lateral change in sedimentary facies between structural highs and lows. Rifting took place through the Triassic and Jurassic, followed by relative tectonic quiescence in the Cretaceous, but as in adjacent areas, the Cenozoic witnessed structural inversion related to plume-generated uplift in the North Atlantic and the activation/reactivation of underlying faults coupled with deformation of the basin fill adjacent to these structures. Regional tilting from the Paleocene to early Eocene led to an influx of siliciclastics into the Dutch Bank Basin. The main play type is thought to consist of Rotliegend Group and Devonian sandstone reservoirs on the West Fladen High, sealed by Zechstein Group anhydrites or Cretaceous/Tertiary mudstones and charged by a deeply buried Devonian (Orcadian) lacustrine source. Although hydrocarbons are interpreted to have utilized normal faults as migration pathways, comparison with adjacent areas and observations of numerous oil seeps on the sea surface suggest that reservoir breach through reactivation of these faults to the seabed poses the main exploration risk. This fault reactivation has resulted from differential uplift combined with synchronous extensional faulting that affected adjacent areas, including the Inner Moray Firth.

Influence of the Neotethys rifting on the development of the Dampier Sub-basin (North West Shelf of Australia), highlighted by subsidence modelling

During the Late Palaeozoic and the Mesozoic, the development and evolution of the North West Shelf of Australia have been mostly driven by rifting phases associated with the break-up of Gondwana. These extensional episodes, which culminated in the opening of the Neotethys Ocean during the Permo-Carboniferous and a series of abyssal plains during the Jurassic-Cretaceous, are characterised by different stress regimes and modes of extension, and therefore had distinctive effects on the margin, and particularly on the Northern Carnarvon Basin. Interpretation of 3D and 2D seismic data enables a structural and stratigraphic analysis of the Late Palaeozoic sediments deposited in the proximal part of the Dampier Sub-basin (Mermaid Nose). Based on their seismic characters, stratigraphic relationship, internal patterns, lateral continuity, and architecture, these units are associated here with the Pennsylvanian?–Early Sakmarian glaciogenic Lyons Group and the Sakmarian–Artinskian Callytharra Formation. The former were deposited in a half-graben whose development is associated with the onset of the Neotethys rifting, and the latter is characterised by restricted deposition, inversion of prograding patterns, and uplift. The integration of seismo-stratigraphic characterisation of the Late Palaeozoic sequences and Mesozoic data from one exploration well (Roebuck-1) enables the construction of subsidence curves for the Mermaid Nose and the interpretation of its geohistory. The tectonic subsidence curves show a striking Permo-Carboniferous rifting phase related to the Neotethys rifting and a discrete Late Jurassic–Early Cretaceous event coeval with the opening and the spreading of the Argo Abyssal Plain. This result points out the predominance of the effects of the Permo-Carboniferous Neotethys episode, whereas the extension related to the Argo Abyssal Plain rifting that occurred later and closer to the studied area, had only limited effects on the subsidence of the proximal Dampier Sub-basin. Therefore, it supports a tectonic model with two distinct modes of extension for the Late Palaeozoic (widespread) and the Mesozoic (localised) rifting phases.

Development of a major polygonal fault system in Upper Cretaceous chalk and Cenozoic mudrocks of the Sable Subbasin, Canadian Atlantic margin

Detailed interpretation of 2D and 3D seismic data from the Sable Subbasin (continental margin of eastern Canada) has revealed an extensive polygonal fault system affecting Upper Cretaceous chalk of the Wyandot Formation (the Wyandot Chalk) and Cenozoic mudrocks of the Banquereau Formation. This paper offers the first detailed study of a basin-scale polygonal fault system affecting a chalk-dominated unit. The Wyandot Chalk is up to 300 m thick and pervasively deformed by small-scale faults that are morphologically and quantitatively similar to those previously described from polygonal fault systems observed in mudrocks of the North Sea, and elsewhere. This suggests that they may have formed due to a common mechanism. The data presented in this paper point towards a lithological control upon the development of the polygonal fault system and argue that the syneresis hypothesis posed by Cartwright and Dewhurst [Geol. Soc. Am. Bull. 110 (1998) 1242] best explains the distribution and initiation of the analysed fault system. 3D seismic attribute maps reveal an orthogonal intersection relationship between polygonal faults and tectonic faults in the study area. This relationship is interpreted to indicate that local stress perturbations around the tectonic faults influenced the propagation of the polygonal faults.

Utilization of seismic attributes for reservoir mapping: A case study from the Cambay Basin, India

Multilayered Hazad sands of Middle Eocene age deposited in a deltaic environment are the main hydrocarbon producers in the south Cambay basin, India. These sands are broadly divided into 12 units (1 to 12) from bottom to top. These individual sand units are further subdivided into smaller subunits which are selectively charged and produce hydrocarbons in different parts of the south Cambay Basin. The study area covers a part of the Gandhar oilfield situated in the Broach-Jambusar block of the basin where subunits 3A and 12A have produced oil and gas in commercial quantities. Due to its widespread deposition and greater thickness, unit 3A was delineated and developed, based on conventional interpretation of 2D seismic data. The development strategy for unit 12A could not be completely resolved in the absence of a precise sand geometry map. A 3D seismic survey was carried out in the study area with one of the objectives being to map the lateral extent of thin pay sands exactly. According to the well data, the thickness of unit 12, consisting of subunits 12A, B and C, varies from 0 to 18 m, and wherever unit 12 is thicker, subunit 12A is present. Unit 12 is not resolved in the available seismic data but its seismic response is detectable. Synthetic seismic modelling has been carried out for a better understanding of the seismic response and for precise calibration. The seismic attributes extracted from the 3D data volume corresponding to unit 12 are utilized to generate a net thickness sand map of this unit using an artificial neural network technique. The sand geometry map of subunit 12A was prepared with the help of a net thickness map of unit 12 and well data. The thickness map of unit 12 helped in mapping the precise sand geometry of unit 12A and also an additional area for cost-effective exploration and development of this pay, which in turn improves the in-place reserves.