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ABSTRACT The sedimentary basins of the South Atlantic have developed into one of the most active regions for petroleum exploration in the whole world. The increase of interest in the oil industry has resulted from the numerous recent giant to supergiant oil and gas discoveries along both the eastern and western continental margins of the South Atlantic in deep and ultradeep waters. The use of the petroleum system concept in the South Atlantic marginal basins provides an effective means of classifying and characterizing the diversity of the oil and gas systems, as well as, a means to aid in the selection of appropriate exploration analogs. The South Atlantic marginal basins also provide some of the best examples of how petroleum systems evolved through time with respect to both their levels of certainty and their areal and stratigraphic limits. An examination of the Orange and Santos basins, in Namibia and Brazil, respectively, provides examples of almost perfect analogs in terms of petroleum system. For example, lacustrine and marine source rocks, similar oil type, almost identical reservoir deposition environments, traps associated with basement highs and vertical migration pathways dominate in each of the basins, with normal faults networks providing the effective carrier. However, there are clear differences when Aptian salt layers are present in the Santos basin and absent in the Namibian basins. Also, differences are observed when thermal evolution is considered. Although no Aptian salt section is present in Namibian basins, and thermal maturity appears to be much higher in the Namibian coast, both basins share almost identical elements and processes of the petroleum system concept. In summary, the aim of this paper is to show how the petroleum system modeling, supported by geochemistry, allows a correlation between counterpart basins across the South Atlantic realm. DISCUSSION The evolution of the South Atlantic sedimentary basins provided the general conditions for the establishment of various petroleum systems. The formation of source rocks, reservoirs and traps are directly related and connected to the phases of the evolution of the passive continental margins (Figure 1): pre-rift, syn-rift, transitional and thermal sag (drift) sequences (Mello, 1988, Mello et al, 1991 and Katz and Mello, 2000).
- Africa > Namibia > South Atlantic Ocean (0.53)
- South America > Brazil > Brazil > South Atlantic Ocean (0.47)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Barremian (0.33)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Turonian (0.30)
- Africa > Namibia > South Atlantic Ocean > Walvis Basin > PEL 71 > PEL 71 (0.99)
- Africa > Namibia > South Atlantic Ocean > Walvis Basin > PEL 71 > PEL 45 (0.99)
- Africa > Namibia > South Atlantic Ocean > Walvis Basin > PEL 71 > PEL 44 (0.99)
- (37 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.95)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.89)
Abstract Driven, primarily, by the desire to image sub salt targets in the GOM, the industry has made significant improvements in towed streamer acquisition technology, to improve imaging through complex over-burdens. This paper will review a new towed streamer technique which makes a full azimuth seismic measurement with ultra-long offsets (14,000m), which was designed to mitigate imaging limitations of the commonly used WAZ designs in the US GOM. The final design was based on a very intensive modeling study, on real and synthetic models, using a finite difference modeling approach. Introduction As the "easy to produce" hydrocarbon reservoirs become more sparse, the industry is exploring in more challenging areas such as deep water, pre-salt, sub basalt etc.. The complexity of these geologies significantly increases the seismic imaging challenges. Conventional marine towed streamer (NAZ) acquires a very limited azimuth range because of the long/thin geometry of the surface receiver spread. While the source generates a wavefield which propogates in all directions, the receiver spread only records a very limited proportion of the reflected wavefield. If the target and over burden geology is relatively benign (low dip and homogeneous) even this limited spread can illuminate the reservoir reasonably consistently. However, if the target and overburden geology is complex, the seismic rays will bend and scatter on their way to and from the reservoir, resulting in inconsistent illumination. Over the last ten years the industry has developed towed marine solutions which generate a more diverse set of ray paths by more fully sampling the azimuth range, which consequently more evenly illuminate target reservoirs in geologically complex areas. These techniques include multi-azimuth (MAZ), wide-azimuth (WAZ), rich-azimuth (RAZ) and more recently Coil Shooting. MAZ is a technique in which a conventional NAZ survey is acquired multiple times using different primary orientations; Generally, the data is merged post stack either using a weighted or unit summation. WAZ is a technique in which multiple vessels are used to extend the range of azimuths collected and RAZ itechnique in which WAZ geometry surveys are repeated in multiple acquisition directions. Coil Shooting is a technique in which a marine towed streamer vessel follows a circular pre-plot. This circular line is then repeated in the inline and crossline direction, to build up fold, offset distribution and azimuth distribution. As well as acquiring a dataset very well sampled in azimuth, the technique benefits from some acquisition efficiencies associated with the very sdowntime (line change) between circular lines. This downtime is of the order of minutes as opposed to hours for conventional race-track acquisition.
- South America > Brazil (0.50)
- North America > United States (0.36)
- North America > Cuba > Gulf of Mexico (0.95)
- South America > Brazil > Brazil > South Atlantic Ocean (0.89)
Time-lapse seismic is an important tool for reservoir management, assisting in the mapping of flooded areas, injection fronts and faults identification. This technology enables a better understanding of the geological model and the fluid flow and is another data source for reservoir management. Several published cases report the successful use of this technology in reservoir management to increase production efficiency; however, in order to gain commercial advantage, it is necessary to identify the moment at which to start the seismic monitoring project. This moment cannot be too early, because the seismic may not be able to identify variations in the reservoir dynamic properties and it cannot be too late because major changes may not be detected and it can be too late for effective action in field management. However, the quantitative assessment of the 4D seismic value is based on simulation models, used to predict the production, with and without seismic acquisition, and there are many uncertainties in the forecasting process in the field development phase. Therefore, in order to ascertain the period of 4D seismic acquisition that allows for an increase in production efficiency and reduces field uncertainties, a study was done to show the effect of 4D seismic at different production times for a simple synthetic case aiming to illustrate the concept of 4D seismic evaluation. Synthetic seismic data were generated from a reference model for several production times and performed the history matching of the simulation model (base model) with production and 4D seismic data.
- South America > Brazil (0.68)
- Europe > Norway (0.46)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- South America > Brazil > Campos Basin (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > ร re Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Seismic (four dimensional) monitoring (1.00)
Abstract In deepwater such as Santos basin pre-salt environment enhanced imaging can be achieved using wide azimuth acquisition geometry (WAZ). There are two options available for seismic imaging: towed streamers and seabed receivers. During field development, surveys usually have a limited size (<300km2). WATS (wide azimuth towed streamers) have operational restrictions due to surface obstructions such as FPSOs, offloading buoys and drilling rigs. Undershooting with multiple vessels is a solution with significant data quality limitation, especially in the context of seismic monitoring (4D). Ocean Bottom Cables (OBC) also have operational issues due to water depth and due to seabed obstructions such as pipelines, and anchor chains. Ocean Bottom Nodes (OBN) provide excellent Full-Azimuth (FAZ) Multi-component (4C) seismic data. OBN can be safely used in areas with both surface and seabed obstructions. Deployed by Remotely Operated Vehicle (ROVs) the nodes provide high repeatability for 4D seismic monitoring. Some OBNs can be mobilized on a vessel of opportunity and can be deployed by a dynamically positioned vessel already working in the field, thus increasing the safety and reducing the cost of the node survey. The technology is ready for commercial applications and spectacular results have been already achieved. The industry is now developing specific business models and operational models for combining nodes with surface towed streamers and with permanent reservoir monitoring OBC. Ocean Bottom Nodes are emerging as a new acquisition method Unlike surface towed streamers and Ocean Bottom Cables (OBC) the Ocean Bottom Nodes (OBN) are autonomous recording systems (Fig 1) and Remotely Operated Vehicles (ROV) (Fig 2) can deploy them safely on the seabed. Each node has seismic sensors, an analog to digital convertor, a clock, memory and battery, they are able to provide continuous records for weeks and month. They also record their tilt, voltage, temperature, and humidity. Because each node has its own clock and keeps its time, Clock drift and synchronization should be handled carefully and may causes delays in data processing but has never caused loss of data. The seismic sensors are a hydrophone and three geophones for four components (4C). The seismic sensors record both primary P waves and secondary Shear waves. The combination of the hydrophones and the geophones enables separation of the P waves to up-going and down-going wavefields. This separation is important for imaging with both primaries and multiples. Ocean bottom nodes are not a new idea. Oceanographers have used them for decades, but recent computing- battery- and ROV- technologies are making them more and more practical and affordable. In addition to the technology push, there is an increasing market pull for nodes for exploration of hard to find oil and for reservoir development and production monitoring.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
Abstract An accurate earth model is key to any successful depth imaging effort. Full waveform inversion is an advanced velocity model building process which uses the full two way wave equation. Existing methods use a ray tracing approach to distribute velocity errors within the model. In this presentation, we will show examples of seismic data processed with the latest technology, including earth model building with full waveform inversion. Introduction The industry has moved to using two-way wave equation migrations(commonly known as reverse time migration), especially in areas of complex geology such as the salt bodies in the Gulf of Mexico and offshore Brazil. The velocity model, including velocity anisotropy, is key to any depth migration effort. The natural next step is to use the two-way wave equation for velocity model building. One of the most advanced tools for velocity model building using the two-way wave equation is Full Waveform Inversion(FWI). Full-waveform inversion uses computer intensive forward modeling of the seismic measurement combined with residual wavefield back propagation to iterate to a final velocity model, which can provide greater detail than tomographic ray tracing approaches. Velocity inversion using full waveform inversion has been used on a number of projects around the world including the GOM, Brazil and the North Sea.
- South America > Brazil (0.93)
- Europe > United Kingdom > North Sea (0.26)
- Europe > Norway > North Sea (0.26)
- (2 more...)
- North America > Cuba > Gulf of Mexico (0.89)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic modeling (1.00)
Abstract Seismic images are only as good as the velocity models used to produce them. As we move from "easy oil" to "difficult oil" targets in sub-salt, sub-basalt and deep complex areas, we can no longer build the simple isotropic models of the past. To fully leverage the potential of new data types (e.g. wide azimuth and long offsets), we have to move to anisotropic imaging with vertical or tilted transversely isotropic (VTI or TTI) models in all geological provinces. Incorporating anisotropy increases our ability both to focus the seismic data and to accurately position the reflectors for drilling decisions. While these goals are achievable with anisotropic models, they are only met when geology information and data from boreholes are intimately incorporated into velocity model building from the very start. We discuss several different approaches for anisotropic model parameter estimation and we illustrate some of the possible strategies with examples from the Gulf of Mexico and West Africa. Introduction Anisotropic depth imaging with VTI or TTI models has become the dominant industry practice in recent years. However deriving all the parameters needed to describe a transversely isotropic medium, throughout a 3D model, suitable for depth imaging is far from trivial. A TTI model requires five parameters: symmetry-axis velocity (VP0), Thomsen parameters e and d, and two angles describing the tilt of the symmetry axis. Over the last decade, we have developed many methods and techniques for deriving anisotropic parameters and building and updating VTI and TTI models for depth imaging. We have organized them in multiple workflows that enable us to pursue flexible approaches, optimally using all the information available in any situation. The three case studies included in this paper illustrate the importance of having a broad portfolio of tools and techniques that allow the design of fit-for-purpose model building strategies in areas with or without good quality well data control. For all of the examples, we build anisotropic models using variations of the generalized workflow described by Zdraveva and Cogan (2011) and compare the results against images and models from previous imaging efforts with isotropic or simple regional VTI models. Because many anisotropic models will fit a single surface-seismic data set, we evaluate the final model correctness not only on image focusing, reduction of residual curvature, and ties to well data, but also on the geological, rock-physics and geomechanical plausibility of the model and image. Anisotropic parameters derivation and different approaches for 3D model building Because surface-seismic data alone do not constrain all anisotropic parameters, an important step of any anisotropic model building workflow is to evaluate Thomsen's parameters and build local anisotropic models around wells where additional information is available. Examples of such techniques include:1D layer-stripping modeling and inversion with well data. Localized tomography with well data (Bakulin et al., 2010a and 2010b). Tomography with uncertainty analysis (Bakulin et al., 2009). Trial-and-error scenarios in combination with 3D tomographic inversion with quick feedback loop.
- South America > Brazil (0.47)
- North America > United States (0.35)
- Africa > Angola (0.29)
- Geology > Geological Subdiscipline > Geomechanics (0.55)
- Geology > Rock Type (0.34)
- Geophysics > Seismic Surveying > Seismic Interpretation > Well Tie (0.91)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.90)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (0.69)
- Africa > Angola > Kwanza Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon (0.98)
- Africa > West Africa (0.89)
The oil and gas industry is among the power that can be purchased for the whose services are used by all industries, top sectors contributing to the proliferation same amount of money doubles about including oil and gas. Signaling of a phenomenon known as every two years. A recent McKinsey Global Managing big data calls for capitalizing these companies have consolidated Institute report defines big data as on economies of scale in order to their information on huge arrays of "datasets whose size is beyond the ability achieve efficiencies that ensure ongoing servers--servers capable of increasingly of typical database software tools data security and virtual 100% accessibility. This is where cloud computing in gigantic data centers ranging in size This translates into datasets on enters the picture. These nine companies (Table 1) in size, with the assumption image of vast amorphous forms that among them own or lease 47 data centers, that "as technology advances over time, have a metaphysical, even mystical, most in the US. the size of datasets that qualify as big relation to solid, three-dimensional data will also increase." However, this vagueness is The Rise in Data Centers Dataset increase follows what is misleading. In reality, all data and the How does the oil and gas industry keep known as Moore's Law, first described entire internet must reside on servers a tight rein on its data while at the by Intel co-founder Gordon Moore in that in turn are housed somewhere. The answer to this question an integrated circuit doubles approximately such as Amazon.com, Apple, has prompted the development of every two years. This has tended Facebook, Google, Hewlett-Packard, cost-effective, secure, ultramodern data to mean that the amount of computing IBM, Microsoft, Twitter, and Yahoo, centers--also known as co-location centers--comparable in size to those owned by Google. Often in nondescript buildings in out-of-the-way places, these are frequently owned by companies with close ties to the telecom industry, as bandwidth is crucial and electricity usage is invariably the centers' largest expense. One of Bastionhost's co-location centers is situated on a 100-acre campus In addition, several copies of Defense data--which offer physical more than 600,000 sq ft of raised white of the data will be made. "The key is, no one wants to do a and low humidity.
- North America > United States (1.00)
- Europe (1.00)
- Asia (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (0.82)
- Information Technology > Cloud Computing (1.00)
- Information Technology > Data Science > Data Mining > Big Data (0.82)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142280, โUltradeepwater- Subsalt-Reservoir Characterization: An Integrated Multiscenario Approach for Development Planning,โ by Olivier Pippi, SPE, Statoil ASA (formerly with BP plc), Mike Mayall, Mike Chandler, SPE, Tim Dodd, Paul Reid, and Paul Taylor, BP plc, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed. Subsea development of clustered deepwater subsalt fields is challenging, technically and economically. With the high cost of appraisal wells, the industry tends to rely on seismic technology, pushing the limits of imaging and characterizing the reservoir by use of seismic attributes. A fully integrated approach that uses all available data should be followed to describe the uncertainty fully and to make an optimized business decision. This work shows a systematic method to integrate information available from a limited data set to validate the description of the field and to perform a full risk and uncertainty analysis supporting the field-development strategy. Introduction Many exploration plays in deepwater basins around the world involve structural closures associated with stratigraphic-trapping elements that are above or against salt diapirs or canopies. Below these often-large salt bodies, seismic imaging can be impaired significantly, which makes the crest of the structure particularly complicated to map. Updip volumes that are close to the salt can be difficult to describe with confidence, yielding large uncertainty about hydrocarbon volumes in place. Reservoir faulting induced by the movement of the salt over geological time introduces significant structural complexity. This complexity adds to common stratigraphic and depositional complexity of deepwater reservoirs deposited in turbidite slope settings. Deepwater turbidite reservoirs can be large erosional channels (typically 1 to 3 km wide and 50 to 200 m thick) or can be sheet-like sands (typically 1 to 5 km wide and 5 to 30 m thick) with various degrees of channel amalgamation. Each type of reservoir poses specific development challenges in terms of continuity and connectivity. Multiscenario Risk and Uncertainty Analysis Given the structural complexity of the field, the wide range of oil-in-place estimates results in making risk and uncertainty analysis difficult to address at the same time. A project close to sanction would have a firmer resources-in-place definition before making a decision. Alternatively, the decision would have flexibility to be phased in over a certain time as new production data become available.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Management (1.00)
Over the past decade, there has been rather vigorous activity in developing simultaneous sourcing and slip-sweep techniques for vibroseis acquisition. Such methods include HFVS and C-HFVS (Krohn et al., 2010), ISS (Howe et al., 2008), DSSS (Bouska, 2010), and HPVA and V1 (Meunier and Bianchi, 2002). These methods provide improved vibrator productivity and create a means of cost-effectively improving source density and thus spatial sampling. Egan et al. (2010) have discussed the link between spatial sampling and resolution (spatial and temporal).
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (0.93)
There appears to be a growing interest in improving subsurface seismic imaging by increasing spatial sampling as a result of increased receiver and/or source density. Cost-effectively improving spatial sampling, however, requires increased vibrator productivity. Some high-productivity techniques now used in survey operations are slip-sweep and independent simultaneous shooting (ISS). However, there is a debate that such methods should be used only by vibrator groups with short sweeps or single vibrators with long sweeps. Can we remove all in-field signal-to-noise enhancement processes and rely strictly on the seismic processing of high trace-density volumes? This paper focuses on the vibrator itself and determines the vibrator performance when driven by short and long sweeps. The experimental results demonstrate that a minimum sweep length is required to avoid significant degradation in vibrator performance at low frequencies (below 20 Hz). Above 20 Hz, the force power spectra with various sweep lengths remain consistent. Moreover, when coupling is poor, a short sweep will produce a better spectrum of the vibrator ground force than a long sweep.