Application of interactive data language in three-dimensional seismic data visualization

Seismic data incorporation in reservoir simulation models history matching (HM) studies has been continuously growing. 4D seismic data, in contrast with well production data, can provide a very good scenario of fluids arrangement along reservoir. In this work we describe how 3D and 4D seismic data gathered in acquisitions performed in Campos Basin was incorporated in Marlim Sul deep water field geological model reconstruction and in assisted HM (AHM). It is taken advantage of both 3D and 4D seismic data in several stages of the study, for instance, in the construction of a new porosity – most influential in impedance – model by using a methodology based on the inversion of synthetic seismic (calculated by petro-elastic model) in porosity through an optimization process that aims to reduce the difference between observed and synthetic impedance, and when defining influential parameters based on fluids displacement registered by seismic signal, by using a technique based on the creation of transmissibility multipliers parameters regions that considers the fluids displacement shown in 4D signal. Another relevant point is the use of information from reservoir and 3D seismic data when weighting the 4D data in the objective function. Combining the above mentioned techniques with the knowledge of the field – supported by the 3D seismic data – which allowed, for instance, identification of faults – where fault transmissibility multipliers were used as parameters in the HM process – a fairly good agreement on the observed well and seismic production data was achieved. HM studies using AHM tools have been shown a much more time-efficient technique when compared to manual HM. The incorporation of 4D seismic data can considerably improve the HM quality by improving the reservoir description, once it increases the ability of describing fluids arrangement and pressure distribution. The techniques successfully applied in the Marlim Sul field HM support these conclusions.

Interpretation of three-dimensional (3D) seismic data from the northern part of central Saudi Arabia allowed mapping of the Permo-Carboniferous Unayzah Formation's aeolian sand deposits and fluvial channels. These types of depositional environments have been associated frequently with better reservoir-quality sandstones within Saudi Arabia. The depositional setting of the Unayzah reservoirs can be highly variable and range from glacial, to lacustrine, to meandering fluvial, to aeolian, to braided stream. Seismic amplitude data were instrumental in mapping a truncation of the upper Unayzah reservoir against the overlying Pre-Khuff Unconformity. The use of seismic attributes, such as coherence and curvature, indicated the existence of faulting and a fluvial channel network at the top of the Unayzah Formation. The integration of well and seismic amplitude data, via acoustic impedance inversion, revealed the direction of potentially higher porosity fairways within the channel system. The structural and depositional architecture depicted in this study is being appraised through drilling of an exploration well.

In the last decade, the sophistication of three-dimensional (3D) seismic data has been applied increasingly to the more precise definition of geological structures containing oil and gas accumulations. In favourable circumstances, it is even possible to define the limits of the hydrocarbons themselves and, in rare cases, show the retreat of hydrocarbon-water contacts in response to sustained oil and gas production. In the early days, 3D seismic data were interpreted in a manner comparable to the interpretation of a grid of two-dimensional (2D) profiles. Equispaced in-lines and cross-lines were abstracted from the total data volume and, with the additional benefit of arbitrary lines and time-slices, interpreters were able to construct time contour maps of selected horizons with increased confidence. However, a significant percentage of the total volume of acquired data was by-passed in this process, and it was not until the advent of interactive trace interpretation systems (the so called work stations) that the interpretation of the full data volume became feasible. Feasibility turned into reality with the development of new and powerful automatic tracking (horizon picking) programs. These enable the interpreter to incorporate data from every common midpoint (CM) in the data volume. In some more advanced programs, selected ‘seed’ lines, which are initially interpreted by hand, are fed to the automatic tracking programs which, in turn, extrapolate the horizon pick until every CMP in the survey has been covered. For any given reflection horizon it is thus possible to generate files of two-way time, amplitude, instantaneous phase, etc. in a framework of x,y coordinates. These files permit the calculation of additional horizon attributes, especially dip and azimuth (Shell Internationale Petroleum Maatschappij BV 1988. Horizon processing techniques for recognition of structural geology on 3D seismic. Research Disclosure 29473). This paper is concerned with the determination and display of the latter two attributes. It will be shown that, with carefully chosen colour display parameters, subtle laterally continuous features that would have been overlooked during traditional interpretation may be interpreted with relative ease and confidence as having geological significance. The techniques employed have much in common with those used in photogeology.

Editor's note: This paper won the Best Poster Paper Award from the 2001 Annual Meeting in San Antonio. The study area consists of 180 miles2 within the Val Verde Basin. A new interpretation is proposed and is based primarily on 3D seismic data. Emphasis is placed on the Lower Permian to Pennsylvanian Section in which hydrocarbons have been found from tight reservoirs. The general stratigraphy is summarized, the focus being on hydrocarbon source, reservoirs, and seal. Seismic lines, spread across the area, illustrate structure. The producing fields sit atop the Foreland Thrust, which was transported as a decollement zone on Mississippian shales. A series of backthrusts is invoked to accommodate the movement of competent rocks up the ramped Foreland Thrust, creating the main structures in the fields. The Foreland Thrust is thought to be the primary migration pathway while the back-thrusts appear to be secondary migration pathways. The new interpretation incorporates 3D seismic, well, and reservoir performance data. The 3D seismic data, in particular, demonstrate the overall sequence stratigraphy of the basin and lead to a new structural interpretation. This interpretation is based mainly on 3D seismic data. Emphasis is placed on the Lower Permian to Pennsylvanian geologic section where hydrocarbons have been found in tight reservoirs. Currently, these reservoirs are being developed by Conoco Inc. in partnership with Tom Brown Inc. Geographically, the study area is located about 120 miles south of Midland in Texas. It encompasses Conoco's 3D seismic coverage in the Val Verde Basin and occupies an area roughly 30 × 6 miles. Geologically, the Val Verde Basin comprises the southern portion of the greater Permian Basin of mid-continent United States. It lies between the Central Basin Platform to the north and the Marathon Uplift to the south (Figure 1). Figure 1. Location map. Based on 2D seismic …

This paper proposes a method for quantitative integration of seismic (elastic) anisotropy attributes with reservoir performance data as an aid in characterization of systems of natural fractures in hydrocarbon reservoirs. This method is demonstrated through application to history matching of reservoir performance using synthetic test cases. Discrete Feature Network (DFN) modeling (Dershowitz et al.1) is a powerful tool for developing field-wide stochastic realizations of fracture networks in petroleum reservoirs. Such models are typically well conditioned in the vicinity of the wellbore through incorporation of core data, borehole imagery, and pressure transient data. Model uncertainty generally increases with distance from the borehole. Threedimensional seismic data provides uncalibrated information throughout the inter-well space. Some elementary seismic attributes such as horizon curvature and impedance anomalies have been used to guide estimates of fracture trend and intensity (P32) (Dershowitz and Herda2) in DFN modeling through geostatistical calibration with borehole and other data. However, these attributes often provide only weak statistical correlation with fracture system characteristics. The presence of a system of natural fractures in a reservoir induces elastic anisotropy that can be observed in seismic data. Elastic attributes such as azimuthally dependent normal moveout velocity (ANMO), reflection amplitude versus azimuth (AVAZ), and shear wave bi-refringence can be inverted from 3D seismic data. Anisotropic elastic theory provides physical relationships among these attributes and fracture system properties such as trend and intensity. Effective elastic media models allow forward modeling of elastic properties for fractured media. A technique has been developed in which both reservoir performance data and seismic anisotropic attributes are used in an objective function for gradient-based optimization of selected fracture system parameters. The proposed integration method involves parallel workflows for effective elastic and effective permeability media modeling from an initial DFN estimate of the fracture system. The objective function is minimized through systematic updates of selected fracture population parameters. Synthetic data cases show that 3D seismic attributes contribute significantly to reduction of ambiguity in estimates of fracture system characteristics in the inter-well rock mass. The method will benefit enhanced oil recovery (EOR) program planning and management, optimization of horizontal well trajectory and completion design, and borehole stability studies.

Integration of 3D and time-lapse 4D seismic data into reservoir modelling and history matching processes poses a significant challenge due to the frequent mismatch between the initial reservoir model, the true reservoir geology, and the pre-production (baseline) seismic data. A fundamental step of a reservoir characterisation and performance study is the preconditioning of the initial reservoir model to equally honour both the geological knowledge and seismic data. In this paper we analyse the issues that have a significant impact on the (mis)match of the initial reservoir model with well logs and inverted 3D seismic data. These issues include the constraining methods for reservoir lithofacies modelling, the sensitivity of the results to the presence of realistic resolution and noise in the seismic data, the geostatistical modelling parameters, and the uncertainties associated with quantitative incorporation of inverted seismic data in reservoir lithofacies modelling. We demonstrate that in a geostatistical lithofacies simulation process, seismic constraining methods based on seismic litho-probability curves and seismic litho-probability cubes yield the best match to the reference model, even when realistic resolution and noise is included in the dataset. In addition, our analyses show that quantitative incorporation of inverted 3D seismic data in static reservoir modelling carries a range of uncertainties and should be cautiously applied in order to minimise the risk of misinterpretation. These uncertainties are due to the limited vertical resolution of the seismic data compared to the scale of the geological heterogeneities, the fundamental instability of the inverse problem, and the non-unique elastic properties of different lithofacies types.

Relevance of the work. The paper considers challenging problems related with outlining of intervals with oil and gas presence in the mature Khylly field by use of latest 3D seismic survey techniques in order to gain larger crude resources base. The purpose of this research is to discover the most promising intervals of target horizons with relatively high reservoir properties outlined by 3D seismic data. The subjects of research are 3D seismic survey data, downhole seismic survey – Vertical Seismic Profiling (VSP) and well logging diagrams. The object of research is the Khylly deposit. The paper describes in brief geological and geophysical characteristics, stratigraphic and lithological features of rocks making the section. It is noted that despite repeated surveys by use of various geological and geophysical techniques, the field setting is not thoroughly studied and it has been covered by 3D seismic survey in 2012. Research results. 3D seismic survey applied across Khylly area is resulted in drawing of 4 structural maps for III and I horizons of Productive Series (PS), Akchagyl and Lower Absheron suites. Taking into account the relevance of structural planes of various stratigraphic levels and III horizon of PS being one of the major reference horizons the paper gives description of structural map drawn for this horizon. The detailed velocity model is designed based on VSP data with wide use of velocity analysis data. It has been made clear that Khylly area has block structure and each block has been described in detail. Based on acquired data it has been recommended to drill exploratory well R-1. Conclusion. Processing and interpretation of seismic data are aimed at solving some geological problems; the main task was to obtain results that ensure the study of the geological structure in the seismic survey area, including tracing of seismic horizons, faults and outlining the areas and section intervals which may be of interest due to possible oil and gas presence. VSP data acquired in well 2012 and velocity analysis made it possible to design velocity model of the section under the study, with the use of which the temporary 3D cube was transformed into a depth cube. The quality of seismic data is good and made it possible to solve the tasks set for this research.

In this Marcellus Shale study, we examine the relationship between microseismic event trends observed in multi-well hydraulic fracture treatments and seismic discontinuity trends extracted from 3D seismic data. The 3D seismic data were pre-processed using t*attenuation to identify zones of high frequency loss in windowed regions throughout the seismic volume. This volume was then input into a discontinuity detection workflow that incorporates dip deviation and Ant-Tracking. Microseismic cluster trends suggest hydraulic fracture treatments produce fractures with approximately N53E to N65E trend. Extracted seismic discontinuities are oriented on average along N52E and N41W trends. Microseismic event clusters with northwest orientation are much less common. Cluster trends are rotated to the east relative to nearby reverse faults, which trend approximately N25E. Information on the orientation of SHmax in the area from borehole breakouts or induced fracture orientations is lacking; however, fluid injection favors opening of pre-existing fractures along the N53-65E trend suggesting that orientation of SHmax is close to this trend. The presence of occasional northwest-southeast trending microseismic event clusters suggests that SHmax and Shmin are similar in magnitude but may be reoriented in response to hydraulic fracture treatment. With this in mind, reservoir fracture models developed to estimate drainage efficiency in this area should incorporate 3D fracture drivers that preferentially enhance fracture permeability along the prominent northeast oriented discontinuity and microseismic cluster trends and reduce permeability in the northwestsoutheast direction.

Seismic data offer valuable spatial information that contributes to the development strategy, such as drilling decisions and well planning. Inverting 3D seismic reflectivity data to impedance unlocks the potential of using seismic data to estimate the lateral variability and to predict reservoir geomechanical behaviour. The geomechanical model contributes for the evaluation of wellbore stability, frackability and drilling direction. The objective of this work is to illustrate the use of seismic derived models for reservoir and geomechanical properties, such as total porosity, total organic carbon (TOC) and rock rigidity. These properties are instrumental to characterize tight reservoirs and useful tools for defining a horizontal well trajectory.The study area has an exploration potential of unconventional reservoirs, targeting tight carbonates from Upper Jurassic. To date, only one well has been drilled in the area of the interest and high quality 3D seismic data is available. The process consists of conducting seismic inversion, using the well and the 3D PSTM seismic data, and resulting in the generation of 3D subsurface impedance model. The well-log relationships between impedance and reservoir quality (effective porosity, source richness) and completion quality (brittleness) were determined and showed high correlation. Hence, 3D rock quality and geomechanical volumes were derived to characterize the behaviour of the reservoir target.Seismic derived properties models yield a better description of the reservoir heterogeneity than using seismic reflectivity data only. The horizontal well trajectory was planned taking into account the observed and significant lateral variability revealed by the 3D models estimated based on seismic inverted data.The results obtained using this methodology demonstrate the importance of integrating geophysical characterisation as a relevant supporting factor in the drilling decision making process. In particular, it validates the use of seismic derived reservoir and completion quality models as an additional tool in the definition of a horizontal well trajectory in a tight/unconventional deep gas target.

In some oilfield where 3D seismic survey has been done, the deeper structure cannot be discovered for poor deep seismic data. Layer stripping technique applied both seismic and gravity data is a solution, but it cannot get satisfied processing effect because the horizontal variation of formation density is ignored. To improve the gravity survey effect in 3D seismic survey area, this paper presents the formation separation technique. Based on 3D seismic depth data and the transformed density data from 3D seismic velocity data, the upper formation's gravity effects are calculated and removed from Bouguer gravity and then the formation‐separated gravity‐anomaly was obtained, which mainly reflects the deeper geological structure. In block XX, the seismic data of shallow formations are excellent but that of top of basement are poor. The formation‐separated gravity‐anomaly processed under the control of 3D seismic data fits well with the known seismic interpretation and wells. It makes the geological interpretation more reliable

By the end of the 20th century, the geology of the Moravian part of the Vienna Basin was fairly well known from hydrocarbon exploration; nevertheless, recently acquired seismic data have provided important new information. Some of the most interesting geological features derived from 3D seismic interpretation are presented in this article. The main focus is on the Badenian deposits which comprise the most important sedimentary succession in terms of thickness, rock volume, tectonic evolution, and hydrocarbon accumulations. Examples from other Neogene stratigraphic stages are also presented. 3D seismic data analysis has contributed to a better understanding of the basin’s geological development in terms of the temporal and spatial relationships between tectonics, depositional environment, and sedimentation. The 3D data have enabled interpreters to identify new potential structural, stratigraphic, and combination hydrocarbon traps, some of which have been confirmed by wells.

Limitations of the seismic method in mapping salt diapirs increase exploration risks while drilling in near-salt areas. An innovative method of 3D joint inverse problem solution for gravity, well-log, and seismic data makes it possible to verify and refine the shape of a salt dome and map hydrocarbon accumulations right beside the salt wall under the salt wing and over the salt dome. It is illustrated by the results for four salt domes in the central axial part of the Dniper-Donets Basin. In half of the cases, joint gravity inversion proved that seismic data provided a reliable salt shape that may be used as the biggest outline. In the other half of the cases, the salt stem outlined by 3D gravity inversion significantly differed from that by 2D and 3D seismic data interpretation. In one case, gravity inversion showed that the size of the salt stem was three times smaller. For all the cases under the salt wing in proximity to the salt dome, near the salt wall, and over the salt dome, localized low-density rock areas were mapped. These areas were associated with commercial hydrocarbon pools. For one, the salt dome location of the commercial pools was verified by drilling. As a result, a new oil field was discovered and named after Academician Schpak. Also, over the same salt dome, the size of the Runovshina field shallow gas pool outline was six times expanded. Four wells drilling outcomes ― three commercial and one dry ― fully confirm the correctness of the shape of the mapped commercial pool with a 100 % commercial probability of success.

This paper discusses current issues related to modeling the lithology of oil and gas-bearing rocks in the old field Zykh using new technologies for processing and interpreting 3D seismic data and geophysical research of wells (GRW) to increase the resource base of the field. The purpose of this research is to identify the most promising lithological sections and intervals of the section that have higher reservoir properties according to the data of 3D and GRW seismic integration. The subjects of research are 3D seismic data and logging curves of geophysical research of wells (GRW), a priori geological and geophysical data accumulated during the period of exploration and operation of the field. The object of research is the Zykh field. The paper presents a brief history of geological and geophysical study, stratigraphy and lithology of the deposition that make up the section of the Zykh field. Research result: 1. Analysis of the obtained data shows that even within individual tectonic blocks (segments), the lithology of fields is variable and one or another fraction dominates during the transition from one block to another. The same is observed in sections A-B, which crosses the field from north to south. Modeling of deposition lithology was not carried out in all segments (tectonic blocks) of fields, but it should be noted that there are not very many of them.

The principal objective of seismic exploration is to determine three geologic parameters, the structural top, the bottom, and the lateral extent of an oil and gas reservoir. Conventional (100%) data is very efficient in locating the structural top and bottom of reservoirs. Two-dimensional (2D) common depth point (CDP) seismic data provides an immense improvement in seismic data quality over conventional (100%) data. This improvement enables the explorer to better visualize and map the reservoir in each direction of the seismic line. Three-dimensional (3D) seismic technology provides even more mappable data and capability. The explorer may visualize every imaginable direction and subtlety of a reservoir. This talk compares conventional (100%), two-dimensional (2D), and three-dimensional (3D) seismic data from the Midcontinent. Case histories of the Douglass (Upper Pennsylvanian) in Texas, the Morrow (Lower Pennsylvanian) in Colorado, the {open_quotes}Chat{close_quotes} (Mississippian) and the Hunton (Silurian-Devonian) in Oklahoma, and the Simpson (Ordovician) in Kansas will be discussed. Major and independent operators can maximize their exploration efforts by integrating existing data with three-dimensional (3D) technology and a solid geologic interpretation.

Summary Time-Lapse (4D) seismic data is used in conjunction with Pressure Transient Analysis (PTA) to quantify the extent and shape of waterflood fronts in a deep-water Gulf of Mexico case study. The waterflood front positions are interpreted on 4D seismic amplitude difference maps and the flood front is modelled in analytical PTA. The asymmetric flood front is investigated in a numerical PTA model and parameter sensitivities for matching both the 4D seismic interpretation and the pressure falloffs tests are explored. The workflow allows for iterations in the interpretation of the 4D flood front as well as updates to the parameters used in the numerical PTA until a satisfactory model is created which matches both the 4D seismic data and the pressure falloffs used in PTA. Together, the joint iterative analysis helps to reduce uncertainty in the products delivered by the individual techniques, resulting in quantitative flood front positions that can be used in assisted history matching of reservoir flow simulations. The case study establishes the value of utilizing 4D seismic in an integrated workflow with PTA techniques for generating flood front constraints that aim to improve forecasting models and guide reservoir management decisions.