The gravity & seismic data jointed formation separation technique for deep structure study

In some oilfields with 3D seismic data, the deeper structure cannot be observed due to poor quality deep seismic data. Layer stripping using both seismic and gravity data is a solution for this problem but it cannot get satisfactory results because the horizontal variations in formation density are ignored. We present a variable-density formation separation technique to address this problem. Based on 3D seismic depth data and laterally-variable density derived from 3D seismic velocity data, the upper formation gravity effect is calculated by forward modeling and removed from the Bouguer gravity. The formation-separated gravity anomaly with variable density is obtained, which mainly reflects the deeper geological structure. In block XX of North Africa, the shallow formations seismic data is excellent but the data at the top of basement is 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.

Strong ocean current influences a marine seismic survey and forces the streamer off-course from the survey line. The sideway drift of the streamer results in that the reflection data are no longer distributed in common midpoint gathers along the survey line but become swath distribution on one side of the ship track. This effect is known as “streamer feathering” which degrades the profile image of the 2D processed seismic data. However, if we have long streamer or closely spaced parallel 2D seismic survey lines, we may turn this deleterious effect into a good opportunity to generate 3D seismic volumes with swath distributed reflection data. We present two case studies in which 2D seismic data were collected offshore eastern Taiwan where the strong Kuroshio Current heavily influenced the ship speed and caused large streamer feathering. The first case is a large-offset 2D seismic profiling data collected using a 6-km long streamer. We processed the swath part of the reflection data in 3D that not only avoids the inappropriate smearing effect in 2D data processing but also generates a 3D seismic volume to help the seismic interpretation. In the second case, we adjusted our 2D survey strategy when realizing that strong Kuroshio Current was causing significant streamer feathering, and collected a set of closely spaced parallel 2D seismic lines. This multi-swath dataset covers a broad area which enables us to generate a 3D seismic volume. Since our datasets are not real 3D seismic data, we have tailored our processing flows to deal with different data configurations and limitations of each dataset. Our results show that not only we have enhanced 2D seismic images of the originally-interested survey lines, but also provide information on 3D geometry of the geological features imaged. The benefits and limitations of utilizing the streamer feathering effect to generate 3D seismic volumes from 2D seismic profile data are reported. Overall, this approach is a considerable way to handle 2D seismic data with large streamer feathering for both avoiding unreliable 2D seismic images and obtaining information on 3D geometry of the geological features imaged.

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.

Modern three-dimensional (3D) seismic data assist not only in delineating reservoir geometry, but also in predicting porosity and lithology variations away from well control. This case study of an oil-producing channel sand in the Taber/Turin area, Alta., Canada illustrates the improvement in reservoir characterization achieved with an integrated approach incorporating both well and seismic information.

This paper describes the full cycle of 4D seismic data integration comprised of workflows related to 4D data analysis, quality control of reservoir models and reservoir model updating using both 4D seismic and well production data. These workflows are applied to a deepwater field, where high quality 4D seismic data is available. In the first step, we analyze 4D seismic data and extract multiple attributes to image changes in reservoir properties. Next, we apply different workflows which link 4D seismic data with the reservoir model. Finally, we update the reservoir model automatically by simultaneously honoring the 4D seismic and well production data. We use a novel approach which incorporates 4D seismic amplitude differences without explicitly modeling the full physics in a joint history matching workflow. Introduction Reservoir monitoring using 4D seismic data is becoming an increasingly important tool for reservoir management (Calvert, 2005). Nevertheless, the quantitative integration of both 4D seismic and historical production data into reservoir simulation models is a challenging task, which recently has become an active direction of research. Huang et al. (1997) applied a stochastic optimization method to minimize the mismatch between synthetic and observed seismic data over a reservoir to achieve simultaneous history-matching of 4D seismic and well-by-well production data. Landa (1997) proposed a gradient-based method to integrate both 4D seismic and pressure transient data. Stephen et al. (2006) developed a workflow for multiple-model history matching through simultaneous comparison of spatial information extracted from 4D seismic data as well as individual well-production data. Employing the Neigbourhood Algorithm (NA) as the sampling engine this workflow was applied to the North Sea Schiehallion field. Skjervheim et al. (2007) presented a version of the Ensemble Kalman Filter (EnKF) for continuous model updating capable to match a combination of production and 4D seismic data. They tested the method on a synthetic case and a North Sea field case. Jin et al. (2007, 2008) proposed the combination of the Very Fast Simulated Annealing (VFSA) method with pilot-point parameterization to solve the 4D seismic history-matching inverse problem and applied the workflow to a synthetic case. Castro (2006) proposed a probabilistic approach to perturb a high-resolution 3D geocellular model for integrating data from diverse sources, such as well logs, geological information, 3D/4D seismic, and production data. This workflow was successfully applied on a reservoir of the Oseberg field. Jin et al. (2011) also proposed a flood front based 4D seismic history matching workflow. In this paper, we present a case study of the full cycle of 4D seismic data integration ranging from basic and qualitative 4D attribute analysis to the advanced 4D seismic history matching workflow. 4D seismic attributes analysis This workflow provides an analysis of 4D seismic differences related to changes in reservoir properties. First, timeshifts between baseline and monitor 3D seismic volumes are computed through cross-correlation. Some initial data preparation usually takes place before the cross-correlation of the datasets, including automatic gain control and trace stacking for signal to noise ratio enhancement. Next, the computed timeshift is removed from the monitor survey in order to obtain meaningful 4D difference attributes. At that point, 4D seismic attributes can be extracted from a given gate around time horizons of interest - usually reservoir tops. For reservoirs with large lateral thickness change, top and base reservoir horizons should be used for attribute calculation. Different types of attributes can be extracted, such as the root mean square (RMS), the normalized RMS difference (NRMSD), etc.

Summary Pre-stack depth migration (PSDM) is one of the most important technologies for accurate subsalt structure imaging. However, in the case of huge salt domes and low signal-to-noise ratios (SNR) of subsalt data, the key to accurate imaging of subsalt structure using PSDM is to establish an accurate velocity model. This paper presents a joint solution of 3D gravity and 3D seismic data. The SNR of seismic data above the several huge salt domes in the area is high, while the SNR below the salt domes is relatively low. Since the target is below the salt domes, the PSDM data can't meet the needs of subsalt structure interpretation. We therefore carried out 3D gravity exploration to solve subsalt structural imaging accuracy problems jointly using 3D gravity data and 3D seismic data. Using the inversion result of 3D gravity formation separation, the cause of clutter in seismic reflections on the interior of salt domes is illustrated and the initial velocity model provided by 3D seismic data is revised in the study area. Through this revised initial velocity model, a new pre-stack depth migrated section with improved subsalt reflection SNR as well as better subsalt structure imaging is achieved. Along with the work flow of joint solution of gravity and seismic data, this paper also gives prerequisites for formation separation technique. Introduction Interval velocity modelling plays a key role in imaging subsalt structure using PSDM technology. Generally, the interval velocity modeling covers two parts: the first is to establish an initial interval velocity model using pre-stack time-migrated seismic data. After PSTM and horizon calibration in the time domain of seismic data, the RMS velocity field as well as the structural model in time domain can be acquired. Once these data are determined, a constrained inversion as well as time-to-depth conversion can be applied to the RMS velocity field to acquire the initial interval velocity model in depth domain. The second part involves using the already established initial interval velocity model in depth domain to apply PSDM to the test line and evaluate the migrated section geophysically and geologically. This is an important step to modify the initial velocity model in depth domain to reasonable solution. The second step is a complex iterative processes, through which the final interval velocity model in depth domain for PSDM processing in the whole work area can be obtained. Obviously, the higher the SNR of seismic data, the finer the layer calibration in the time domain, and the more accurate the established initial interval velocity model. Here, the layer calibration in time domain isn't the chronostratigraphic calibration of interfaces but the interval velocity variation calibration of interfaces, taking corresponding well logging data and underground geological features as constraints for inversion of the RMS velocity field. One of the criterions to judge the reasonability of initial or inverted interval velocity model is the leveled reflection events in the CRP gather. Therefore, we can't judge whether the interval velocity model is reasonable or not if the SNR in the CRP gather is too low. Thus, the SNR of seismic data is an important factor in determining the precision of interval velocity model.

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.

Summary Elastic seismic inversion is a tool frequently used in analysis of seismic data. Elastic inversion relies on a simplified seismic model and generally produces 3D cubes for compressional-wave velocity, shear-wave velocity, and density. By applying rock-physics theory, such volumes may be interpreted in terms of lithology and fluid properties. Understanding the robustness of forward and inverse techniques is important when deciding the amount of information carried by seismic data. This paper suggests a simple method to update a reservoir characterization by comparing 4D-seismic data with flow simulations on an existing characterization conditioned on the base-survey data. The ability to use results from a 4D-seismic survey in reservoir characterization depends on several aspects. To investigate this, a loop that performs independent forward seismic modeling and elastic inversion at two time stages has been established. In the workflow, a synthetic reservoir is generated from which data are extracted. The task is to reconstruct the reservoir on the basis of these data. By working on a realistic synthetic reservoir, full knowledge of the reservoir characteristics is achieved. This makes the evaluation of the questions regarding the fundamental dependency between the seismic and petrophysical domains stronger. The synthetic reservoir is an ideal case, where properties are known to an accuracy never achieved in an applied situation. It can therefore be used to investigate the theoretical limitations of the information content in the seismic data. The deviations in water and oil production between the reference and predicted reservoir were significantly decreased by use of 4D-seismic data in addition to the 3D inverted elastic parameters. Introduction It is well known that the information in seismic data is limited by the bandwidth of the seismic signal. 4D seismics give information on the changes between base and monitor surveys and are consequently an important source of information regarding the principal flow in a reservoir. Because of its limited resolution, the presence of a thin thief zone can be observed only as a consequence of flow, and the exact location will not be found directly. This paper addresses the question of how much information there is in the seismic data, and how this information can be used to update the model for petrophysical reservoir parameters. Several methods for incorporating 4D-seismic data in the reservoir-characterization workflow for improving history matching have been proposed earlier. The 4D-seismic data and the corresponding production data are not on the same scale, but they need to be combined. Huang et al. (1997) proposed a simulated annealing method for conditioning these data, while Lumley and Behrens (1997) describe a workflow loop in which the 4D-seismic data are compared with those computed from the reservoir model. Gosselin et al. (2003) give a short overview of the use of 4D-seismic data in reservoir characterization and propose using gradient-based methods for history matching the reservoir model on seismic and production data. Vasco et al. (2004) show that 4D data contain information of large-scale reservoir-permeability variations, and they illustrate this in a Gulf of Mexico example.

In support of the South Florida Water Management District (SFWMD) Floridan Aquifer System (FAS) and Aquifer Storage & Recovery (ASR) groundwater development & management programs, high resolution broadband seismic test data was acquired and processed in the Lake Okeechobee area. As part of the FAS and ASR development plans SFWMD identified the need for improved delineation and characterization of the FAS in terms of stratigraphic and hydro-geologic structure. High resolution 2D and 3D seismic acquisition, data processing & modeling, and integrated well log analysis, originally developed for deep oil and gas exploration, have been successfully adapted for high-definition geomorphologic and intra-stratigraphic characterization of the Floridan Aquifer System to depths in excess of 3,000 feet (bgs). In addition, the seismic survey programs were designed to evaluate the potential for identifying zones of deep karst structures that can provide hydro-geologic information concerning vertical and lateral flow of groundwater between major permeable zones within the Floridan aquifers. Based on results from the 2D and 3D seismic test surveys it is shown that the required seismic bandwidth of processed seismic data to identify complex FAS faults and fracture systems is approximately 10 Hz to 120 Hz. The required broadband seismic data is also essential for additional attributes processing to identify zones of intra-stratigraphic karst structures that can affect the long term migration and/or containment of groundwater within FAS confined aquifers. Location and seismic attributes knowledge of faults and fractures systems, augmented with detailed borehole and well log information, is critical to the future placement and installation of deep injection and groundwater production wells. In this presentation, we identify the areas of investigation and local FAS geology, summarize aspects of the seismic surveys, and present modeling and interpretation examples from the 2D and 3D data. From the SFWMD Lake Okeechobee seismic test program we present a summary review of other seismic methods and applications for future development and adaptation to similar groundwater exploration and aquifer investigation projects.

The scale property of the wavelet transform provides a framework for studying the scale properties of seismic and reservoir data. Seismic data are influenced by variations in earth properties that change over distances that are comparable to the wavelength of the seismic source, typically tens of meters. Log and outcrop measurements of earth properties cover a wide range of scales, from millimeter to kilometers. For petroleum exploration, 3D seismic data can be acquired over an entire producing field, but log and outcrop measurements are limited to well bores and the surface of the earth. Geostatistics provides a framework for combining fine scale measurements of rock properties in wells and at the surface of the earth with estimates of the variance of the properties. Based on these inputs, realizations are produced that match the actual field measurements and the estimated variance statistics of a given property. Geostatistical realizations of rock properties are accurate at the well locations, but can become unconstrained between well locations. In current practice, interpreted horizons and facies from seismic data are used as constraints. This requires interpretation, and the seismic data are rarely used directly. We propose using the scale property of the wavelet transform as a means for direct combination of reservoir and seismic data. Previous studies of each properties suggest a fractal relationship between scales. A given geostatistical realization of rock properties contains data (or estimates of data) from a wide range of scales. We propose using a 3D wavelet transformation of geostatistical reservoir data to characterize the reflectivity scale spectrum and the relation between reflectivity at different scales in the reservoir. 3D seismic data from the reservoir will contain information at a much narrower range of scales. Using the extracted scale information from the geostatistical data, we replace the geostatistical data at seismic scales with normalized wavelet transform coefficients from the seismic data. An inverse wavelet transform would then provide a realization of reflectivity that is constrained by both seismic and reservoir data. In the initial phase of this research, we are using wavelet transforms to characterize the scale properties of synthetic reservoir and seismic data. If successful, the technique will be tested on field data.

Convolutional neural networks (CNNs) is a type of supervised learning technique that can be directly applied to amplitude data for seismic data classification. The high flexibility in CNN architecture enables researchers to design different models for specific problems. In this study, I introduce an encoder-decoder CNN model for seismic facies classification, which classifies all samples in a seismic line simultaneously and provides superior seismic facies quality comparing to the traditional patch-based CNN methods. I compare the encoder-decoder model with a traditional patch-based model to conclude the usability of both CNN architectures. Presentation Date: Wednesday, October 17, 2018 Start Time: 8:30:00 AM Location: 204B (Anaheim Convention Center) Presentation Type: Oral

Abstract. A geohazard assessment workflow is presented that maximizes the use of 3D seismic reflection data to improve the safety and success of offshore scientific drilling. This workflow has been implemented for International Ocean Discovery Program (IODP) Proposal 909 that aims to core seven sites with targets between 300 and 1000 m below seabed across the north-western Greenland continental shelf. This glaciated margin is a frontier petroleum province containing potential drilling hazards that must be avoided during drilling. Modern seismic interpretation techniques are used to identify, map and spatially analyse seismic features that may represent subsurface drilling hazards, such as seabed structures, faults, fluids and challenging lithologies. These hazards are compared against the spatial distribution of stratigraphic targets to guide site selection and minimize risk. The 3D seismic geohazard assessment specifically advanced the proposal by providing a more detailed and spatially extensive understanding of hazard distribution that was used to confidently select eight new site locations, abandon four others and fine-tune sites originally selected using 2D seismic data. Had several of the more challenging areas targeted by this proposal only been covered by 2D seismic data, it is likely that they would have been abandoned, restricting access to stratigraphic targets. The results informed the targeted location of an ultra-high-resolution 2D seismic survey by minimizing acquisition in unnecessary areas, saving valuable resources. With future IODP missions targeting similarly challenging frontier environments where 3D seismic data are available, this workflow provides a template for geohazard assessments that will enhance the success of future scientific drilling.

Crosswell seismic data and 3D seismic data are seismic response of different frequency band from the same geologic target. Crosswell seismic data possesses very high resolution in comparing with 3D seismic data for its higher main frequency and broader frequency band. However crosswell seismic data only exist between source well and receiver well, while 3D seismic data has excellent spatial distribution. It is possible to integrate different types of data and get more reliable underground information (Lines et al., 1988; Hu et al.,2007; Heinche et al., 2006). Here we put forward joint frequency expanding (JFE) method of crosswell seismic data and 3D seismic data. We expand 3D seismic data frequency band according to crosswell seismic data, and improve the resolution ability of 3D seismic data. First we use 3D seismic data and crosswell data to build 3D seismic reflect coefficient model, which possesses high resolution, and is consistent with 3D seismic data in structure. Second we use this reflect coefficient model as constraining condition, and joint inversion algorithm is used to get inverted reflect coefficients from 3D seismic data. Finally according to time‐frequency analysis of 3D seismic data, we choose an appropriate high resolution wavelet to convolve with the inverted reflect coefficients, and produces high resolution 3D seismic data. Here we design a processing flow and applied it to Ken 71 data of ShengLi oil field. With the help of crosswell seismic data, 3D seismic data resolution is improved, main frequency is increased from 35Hz to 75Hz, and frequency band is also widened by 30Hz.

On the value of 3D seismic amplitude data to reduce uncertainty in the forecast of reservoir production

Integration of 3D Seismic & Dynamic Data Improves Interpretation of Structural Features Hamad Bu Al Rougha; Hamad Bu Al Rougha ZADCO, Abu Dhabi, UAE Search for other works by this author on: This Site Google Scholar M. Yousef Al-Henshiri; M. Yousef Al-Henshiri ZADCO, Abu Dhabi, UAE Search for other works by this author on: This Site Google Scholar Naeema Khouri; Naeema Khouri ZADCO, Abu Dhabi, UAE Search for other works by this author on: This Site Google Scholar K. Arisaka; K. Arisaka ZADCO, Abu Dhabi, UAE Search for other works by this author on: This Site Google Scholar A. Sultan A. Sultan ZADCO, Abu Dhabi, UAE Search for other works by this author on: This Site Google Scholar Paper presented at the Abu Dhabi International Conference and Exhibition, Abu Dhabi, United Arab Emirates, October 2004. Paper Number: SPE-88692-MS https://doi.org/10.2118/88692-MS Published: October 10 2004 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Al Rougha, Hamad Bu, Al-Henshiri, M. Yousef, Khouri, Naeema, Arisaka, K., and A. Sultan. "Integration of 3D Seismic & Dynamic Data Improves Interpretation of Structural Features." Paper presented at the Abu Dhabi International Conference and Exhibition, Abu Dhabi, United Arab Emirates, October 2004. doi: https://doi.org/10.2118/88692-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)Abu Dhabi International Petroleum Exhibition and Conference Search Advanced Search Abstract Well tests are often used to investigate reservoir heterogeneities such as fractures, conductivity of faults, and matrix permeability. Attributing a measured pressure response to a particular geological feature is problematic, as many different solutions will fit the same pressure response. Data integration is the key to understanding well pressure transients and the underlying geology controlling them.A recently acquired and interpreted 3D seismic survey indicated the reservoir contained numerous strike slip faults. To reduce the uncertainty associated with reservoir characterization, a multidisciplinary team comprising of geophysicists, geologists and reservoir engineers selected an area of the reservoir to focus their efforts. The integration of the 3D seismic with dynamic data provides a possible means of validating the interpretation.Anomalous transient pressure data were identified on five wells. Initial interpretations proved ambiguous with several possible geological reasons. Close examination of the 3D seismic data indicated in each case the presence of a fault. Faults were found to be the likely structural anomalies that have been detected by seismic and well test data. The fault throw, conductivity and its distance to the wellbore were estimated. The transient pressure data enabled us to evaluate the faults as sealing.Once the integration perception was adopted, and high quality data became available, concerns with the 3D seismic interpretation data and the uncertainties associated with pressure transient data that were initially ambiguous began to make sense. Keywords: integration, boundary, reservoir characterization, good match, interpretation, seismic data, drillstem testing, drillstem/well testing, reservoir, upstream oil & gas Subjects: Reservoir Characterization, Formation Evaluation & Management, Seismic processing and interpretation, Drillstem/well testing Copyright 2004, Society of Petroleum Engineers You can access this article if you purchase or spend a download.