The influence of volcanic rocks on the characterization of Rosebank Field – new insights from ocean-bottom seismic data and geological analogues integrated through interpretation and modelling

2016 ◽  
Vol 8 (1) ◽  
pp. 373-384 ◽  
Author(s):  
S. Poppitt ◽  
L. J. Duncan ◽  
B. Preu ◽  
F. Fazzari ◽  
J. Archer
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Volcanic Rocks ◽  
Flood Basalt ◽  
Ocean Bottom ◽  
Volcanic System ◽  
Field Development ◽  
Velocity Models ◽  
Depth Prediction

AbstractDuring Late Paleocene–Early Eocene times, the modern Rosebank structure was located at the juxtaposition of the easterly advancing Flett volcanic system and the northerly prograding Flett delta. As a result, the Rosebank reservoir sandstones are interstratified with volcanic and volcaniclastic rocks, offering challenges for reservoir imaging, depth prediction and reservoir characterization. These challenges have driven the application of Ocean Bottom Node (OBN) seismic technology. OBN data have yielded improved velocity models for depth conversion, better reservoir definition and key insights to aid the modelling of sand distribution from seismic attributes. Spectral decomposition of the OBN seismic data has facilitated the extraction of distinct volcanic subunits, whilst spectral enhancement has enabled visualization of complex stacking patterns within individual igneous layers. To complement the seismic analysis, detailed geological analogue studies have been undertaken in volcanic provinces such as the Palaeogene volcanic district of SE Greenland and the Columbia River Flood Basalt Province, USA. No single outcrop provides a definitive analogy to Rosebank, but each offers insights that provide an important link to understanding and managing the main subsurface uncertainties associated with field development. Integration of these multiple workflows have improved the reservoir characterization and provided the foundation for the optimization of the field development plan.

Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

2021 ◽  
Author(s):  
Rick Schrynemeeckers
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Time Lapse ◽  
Field Trials ◽  
Detection Methods ◽  
Ocean Bottom ◽  
Field Development ◽  
Dense Grid ◽  
Hydrocarbon Charge ◽  
Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

Seismic Qualitative and Quantitative Analysis for Reservoir Characterization of Globigerina BH Gas Field, North East Java Basin.

2021 ◽  
Author(s):  
I. Sumantri
Keyword(s):  
Quantitative Analysis ◽  
Seismic Data ◽  
Quantitative Methods ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Analysis Model ◽  
Gas Reservoir ◽  
Qualitative And Quantitative ◽  
North East ◽  
Exploration Well

BH field is one of the Globigerina limestone gas reservoir that exhibits strong seismic direct hydrocarbon indicator (DHI). This field is a 4-way dip faulted closure with Globigerina limestone as the main reservoir objective. The field was discovered back in 2011 by BH-1 exploration well and successfully penetrated about 350ft gross gas pay. BH-1 well was plugged and abandoned as Pliocene Globigerina limestone Mundu-Selorejo sequence gas discoveries. The laboratory analysis of sampled gas consists of 97.8% of CH4 and indicating a biogenic type of gas. This is the only exploration well drilled in this field and located on the crest of the structure. Seismic analysis both qualitative and quantitative, are common tools in delineating and characterizing reservoir. These methods usually make use of seismic data and well log collaboratively in the quest to reveal reservoir features internally. The lack of appraisal well in the area of study made the reservoir characterization process must be carried out thoroughly, incorporating several seismic datasets, both PSTM and PSDM, seismic gathers and stacks. Bounded by appraisal well limitation, this research looks into Gassmann's fluid substitution modeling, seismic forward modeling to confirm the DHI flat spot presence in the seismic, as well as seismic AVO analysis. Meanwhile, for quantitative analysis, model-based seismic post-stack inversion and simultaneous seismic pre-stack inversion were conducted in order to delineate the distribution of Globigerina limestone gas reservoir in BH Field. Through comprehensive analyses of qualitative and quantitative methods, this research may answer the challenge on how to intensively utilize seismic data to compensate the lack of appraisal well data in order to keep delivering a proper subsurface reservoir delineation.

Applications of quantitative prestack seismic analysis to unconventional resource play characterization in the Permian/Delaware Basin

2019 ◽  
Vol 38 (2) ◽  
pp. 106-115 ◽  
Author(s):  
Phuong Hoang ◽  
Arcangelo Sena ◽  
Benjamin Lascaud
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Seismic Inversion ◽  
Reservoir Properties ◽  
Yield Attributes ◽  
Horizontal Drilling ◽  
Delaware Basin ◽  
Unconventional Resource

The characterization of shale plays involves an understanding of tectonic history, geologic settings, reservoir properties, and the in-situ stresses of the potential producing zones in the subsurface. The associated hydrocarbons are generally recovered by horizontal drilling and hydraulic fracturing. Historically, seismic data have been used mainly for structural interpretation of the shale reservoirs. A primary benefit of surface seismic has been the ability to locate and avoid drilling into shallow carbonate karsting zones, salt structures, and basement-related major faults which adversely affect the ability to drill and complete the well effectively. More recent advances in prestack seismic data analysis yield attributes that appear to be correlated to formation lithology, rock strength, and stress fields. From these, we may infer preferential drilling locations or sweet spots. Knowledge and proper utilization of these attributes may prove valuable in the optimization of drilling and completion activities. In recent years, geophysical data have played an increasing role in supporting well planning, hydraulic fracturing, well stacking, and spacing. We have implemented an integrated workflow combining prestack seismic inversion and multiattribute analysis, microseismic data, well-log data, and geologic modeling to demonstrate key applications of quantitative seismic analysis utilized in developing ConocoPhillips' acreage in the Delaware Basin located in Texas. These applications range from reservoir characterization to well planning/execution, stacking/spacing optimization, and saltwater disposal. We show that multidisciplinary technology integration is the key for success in unconventional play exploration and development.

Depth-consistent reflection tomography using PP and PS seismic data

Geophysics ◽  
2005 ◽  
Vol 70 (5) ◽  
pp. U51-U65 ◽  
Author(s):  
Stig-Kyrre Foss ◽  
Bjørn Ursin ◽  
Maarten V. de Hoop
Keyword(s):  
Seismic Data ◽  
Optimization Procedure ◽  
Transversely Isotropic ◽  
Data Depth ◽  
Image Point ◽  
Ocean Bottom ◽  
Data Set ◽  
Scattering Angle ◽  
Velocity Models ◽  
Reflection Tomography

We present a method of reflection tomography for anisotropic elastic parameters from PP and PS reflection seismic data. The method is based upon the differential semblance misfit functional in scattering angle and azimuth (DSA) acting on common-image-point gathers (CIGs) to find fitting velocity models. The CIGs are amplitude corrected using a generalized Radon transform applied to the data. Depth consistency between the PP and PS images is enforced by penalizing any mis-tie between imaged key reflectors. The mis-tie is evaluated by means of map migration-demigration applied to the geometric information (times and slopes) contained in the data. In our implementation, we simplify the codepthing approach to zero-scattering-angle data only. The resulting measure is incorporated as a regularization in the DSA misfit functional. We then resort to an optimization procedure, restricting ourselves to transversely isotropic (TI) velocity models. In principle, depending on the available surface-offset range and orientation of reflectors in the subsurface, by combining the DSA with codepthing, the anisotropic parameters for TI models can be determined, provided the orientation of the symmetry axis is known. A proposed strategy is applied to an ocean-bottom-seismic field data set from the North Sea.

IDENTIFICATION OF GAS HYDRATES AND BOTTOM SIMULATING REFLECTORS IN FAR OFFSET SEISMIC IMAGES

2021 ◽  
pp. 1-60
Author(s):  
Darrell A. Terry ◽  
Camelia C. Knapp
Keyword(s):  
Gas Hydrates ◽  
Seismic Data ◽  
Single Channel ◽  
Seismic Analysis ◽  
Cost Effective ◽  
Ocean Bottom ◽  
Bottom Simulating Reflector ◽  
Avo Analysis ◽  
Bottom Simulating Reflectors ◽  
Seismic Images

The presence of marine gas hydrates is routinely inferred based on the identification of bottom simulating reflectors (BSRs) in common depth-point (CDP) seismic images. Additional seismic studies such as amplitude variation with offset (AVO) analysis can be applied for corroboration. Though confirmation is needed by drilling and sampling, seismic analysis has proven to be a cost-effective approach to identify the presence of marine gas hydrates. Single channel far offset seismic images are investigated for what appears to be a more reliable and cost-effective indicator for the presence of bottom simulating reflectors than traditional CDP processing or AVO analysis. A non-traditional approach to processing seismic data is taken to be more relevant to imaging the gas/gas hydrate contact. Instead of applying the traditional CDP seismic processing workflows from the oil industry, we more carefully review the significant amount of information existing in the data to explore how the character of the data changes as offset angle increases. Three cases from different environments are selected for detailed analysis. These include 1) stratigraphy running parallel with the ocean bottom; 2) a potential bottom simulating reflector, running parallel to the ocean bottom, and cross-cutting dipping reflections, and 3) a suspected thermal intrusion without a recognizable bottom simulating reflector. This investigation considers recently collected multi-channel seismic data from the deep waters of the central Aleutian Basin beneath the Bering Sea, the pre-processing of the data sets, and the methodology for processing and display to generate single channel seismic images. Descriptions are provided for the single channel near and far offset seismic images for the example cases. Results indicate that BSRs related to marine gas hydrates, and originating due to the presence of free gas, are more easily and uniquely identifiable from single channel displays of far offset seismic images than from traditional CDP displays.

Reservoir characterization over the Lille Prinsen and Ivar Aasen fields in the Norwegian North Sea using ocean-bottom-node seismic data — A case study

2021 ◽  
pp. 1-64
Author(s):  
Satinder Chopra ◽  
Ritesh Kumar Sharma ◽  
Mikal Trulsvik ◽  
Adriana Citlali Ramirez ◽  
David Went ◽  
...  
Keyword(s):  
North Sea ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Late Triassic ◽  
Ocean Bottom ◽  
Impedance Inversion ◽  
High Area ◽  
Elastic Impedance

An integrated workflow is proposed for estimating elastic parameters within the Late Triassic Skagerrak Formation, the Middle Jurassic Sleipner and Hugin Formations, the Paleocene Heimdal Formation and Eocene Grid Formation in the Utsira High area of the Norwegian North Sea. The proposed workflow begins with petrophysical analysis carried out at the available wells. Next, model-based prestack simultaneous impedance inversion outputs were derived, and attempts were made to estimate the petrophysical parameters (volume of shale, porosity, and water saturation) from seismic data using extended elastic impedance. On not obtaining convincing results, we switched over to multiattribute regression analysis for estimating them, which yielded encouraging results. Finally, the Bayesian classification approach was employed for defining different facies in the intervals of interest.

Quantitative 4D Seismic Assisted History Matching Using Ensemble-Based Methods on the Vilje Field

2020 ◽  
Author(s):  
Konrad Wojnar ◽  
Jon S?trom ◽  
Tore Felix Munck ◽  
Martha Stunell ◽  
Stig Sviland-Østre ◽  
...  
Keyword(s):  
Decision Making ◽  
Seismic Data ◽  
History Matching ◽  
Reservoir Characterization ◽  
Reservoir Management ◽  
History Match ◽  
Field Development ◽  
Qualitative And Quantitative ◽  
Reservoir Models ◽  
4D Seismic

Abstract The aim of the study was to create an ensemble of equiprobable models that could be used for improving the reservoir management of the Vilje field. Qualitative and quantitative workflows were developed to systematically and efficiently screen, analyze and history match an ensemble of reservoir simulation models to production and 4D seismic data. The goal of developing the workflows is to increase the utilization of data from 4D seismic surveys for reservoir characterization. The qualitative and quantitative workflows are presented, describing their benefits and challenges. The data conditioning produced a set of history matched reservoir models which could be used in the field development decision making process. The proposed workflows allowed for identification of outlying prior and posterior models based on key features where observed data was not covered by the synthetic 4D seismic realizations. As a result, suggestions for a more robust parameterization of the ensemble were made to improve data coverage. The existing history matching workflow efficiently integrated with the quantitative 4D seismic history matching workflow allowing for the conditioning of the reservoir models to production and 4D data. Thus, the predictability of the models was improved. This paper proposes a systematic and efficient workflow using ensemble-based methods to simultaneously screen, analyze and history match production and 4D seismic data. The proposed workflow improves the usability of 4D seismic data for reservoir characterization, and in turn, for the reservoir management and the decision-making processes.

Integrated 2D 4-C OBC velocity analysis of near-seafloor sediments, Green Canyon, Gulf of Mexico

Geophysics ◽  
2008 ◽  
Vol 73 (6) ◽  
pp. B109-B115 ◽  
Author(s):  
Michael V. DeAngelo ◽  
Paul E. Murray ◽  
Bob A. Hardage ◽  
Randy L. Remington
Keyword(s):  
Seismic Data ◽  
Velocity Analysis ◽  
Ocean Bottom ◽  
Reflection Mode ◽  
Velocity Models ◽  
Velocity Information ◽  
Interval Velocities ◽  
Seafloor Sediments ◽  
Vital Element

Using 2D four-component ocean-bottom-cable (2D 4-C OBC) seismic data processed in common-receiver gathers, we developed robust [Formula: see text] and [Formula: see text] interval velocities for the near-seafloor strata. A vital element of the study was to implement iterative interpretation techniques to correlate near-seafloor P-P and P-SV images. Initially, depth-equivalent P-P and P-SV layers were interpreted by visually matching similar events in both seismic modes. Complementary 1D ray-tracing analyses then determined interval values of subsea-floor [Formula: see text] and [Formula: see text] velocities across a series of earth layers extending from the seafloor to below the base of the hydrate stability zone (BHSZ) to further constrain these interpretations. Iterating interpretation of depth-equivalent horizons with velocity analyses allowed us to converge on physically reasonable velocity models. Simultaneous [Formula: see text] and [Formula: see text] velocity analysis provided additional model constraints in areas where data quality of one reflection mode (usually [Formula: see text] in the near-seafloor environments) would not provide adequate information to derive reliable velocity information.

Synergistic integration of seismic and geologic data for modeling petrophysical properties

2020 ◽  
Vol 39 (3) ◽  
pp. 164-169
Author(s):  
Yuan Zee Ma ◽  
David Phillips ◽  
Ernest Gomez
Keyword(s):  
Neural Networks ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Integrated Approach ◽  
Reservoir Modeling ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Field Development ◽  
Realistic Description ◽  
Geologic Data

Reservoir characterization and modeling have become increasingly important for optimizing field development. Optimal valuation and exploitation of a field requires a realistic description of the reservoir, which, in turn, requires integrated reservoir characterization and modeling. An integrated approach for reservoir modeling bridges the traditional disciplinary divides and tears down interdisciplinary barriers, leading to better handling of uncertainties and improvement of the reservoir model for field development. This article presents the integration of seismic data using neural networks and the incorporation of a depositional model and seismic data in constructing reservoir models of petrophysical properties. Some challenging issues, including low correlation due to Simpson's paradox and under- or overfitting of neural networks, are mitigated in geostatistical analysis and modeling of reservoir properties by integrating geologic information. This article emphasizes the integration of well logs, seismic prediction, and geologic data in the 3D reservoir-modeling workflow.

Buzios Drainage Strategy: A Combination Of Reservoir Characterization, Risks Mitigation And Unique Contract Features

2021 ◽  
Author(s):  
Victor Silva ◽  
Ana Moliterno ◽  
Carlos Henrique Araujo ◽  
Francis Pimentel ◽  
Jose Ronaldo Melo ◽  
...  
Keyword(s):  
Data Acquisition ◽  
Deep Water ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Dynamic Modelling ◽  
Seismic Survey ◽  
Ocean Bottom ◽  
Sweep Efficiency ◽  
Tax Regimes ◽  
The Right

Abstract Petrobras acquired the right to produce 3.058 billion boe under the Transfer of Rights (ToR) in Buzios field, which still has a recoverable surplus, recently auctioned by the Brazilian Petroleum Regulatory Agency. Properly planning the production development of a supergiant field and under two tax regimes, requires a large multidisciplinary effort of data acquisition, characterization and modelling. Located in the Santos Basin Pre-Salt Pole, the Buzios field is a deep-water supergiant that has a large thickness of carbonate reservoirs, with significant areal and vertical variation. The presence of faults, fractures, karsts and other diagenetic processes adds complexity to the field, which motivated the development and implantation of industry innovations to enable its development. The presence of high levels of CO2 and H2S in the reservoir fluid, the risk of inorganic scaling and asphaltene deposition and risks of early fluid channeling and low sweep efficiency due to the aforementioned geological complexities are challenges that need to be addressed. One of these challenges is to ensure a better seismic data for the reservoir characterization. The 3D seismic data from a streamer acquisition did not have sufficient quality for this. The geological complexity of the field, the great reservoir depth and mainly the very irregular topography of the overlying evaporitic sequence indicated the need for rich azimuth seismic data. This led to the world's largest ultra-deep water seismic survey using Ocean Bottom Nodes (OBN) technology. This paper will address the static and dynamic data acquisition from the wells and the Early Productions Systems (EPS), as well as the challenges that arose and were faced by Petrobras through technology and innovation, and the complexity of the reservoir dynamic modelling. Furthermore, the OBN seismic acquisition in Buzios will be discussed in more detail, as well as the frontier that this acquisition opens to the development of the field.

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