First EAGE Conference on Deepwater Equatorial Margin: New Energy Frontier for South America

This paper is a description of the many ways we can acquire seismic data in challenging areas of the Equatorial Margin of South America.

The amplitude versus offset (AVO) technique is well established as a “direct hydrocarbon indicator” for some plays but it is well known that it can be also a good lithology indicator. In some areas of Potiguar basin, reservoir quality makes it difficult to apply AVO as a fluid indicator. It represents a good opportunity to try to apply the method for reservoir quality forecast. We observed noticeable velocity anisotropy in laboratory data available from two wells in a potentially prolific area. The available sampling and measurement capabilities does not allow a complete anisotropy characterization, we are able to estimate only two anisotropy parameters, because we have only core plugs vertically and horizontally oriented. However, the seismic processing in the area involved anisotropic migration, and we have a seismic-derived anisotropic parameter in both wells. We used the laboratory and seismic-derived information to help us to construct AVO scenarios in the area. Here we will compare usual AVO modeling with anisotropic case and compare “good” and “poor” reservoir modeling in both cases.

An in-depth investigation of prospective sub-basins along Brazil’s equatorial margin, highlighting seismic facies of the Early Cretaceous intervals and exploring analogous plays in the Guyana Basin and Western Africa.

Knowledge of ocean circulation is necessary at operational sites in order to monitor, simulate, and predict ocean dynamics with the goal of attaining protective schemes in the planning of crises, in order to build action plans for oil spills and minimize environmental damage. The environmental assessment of potentially affected ecosystems is crucial since various environments have unique sensitivities and can sustain a variety of harms. The use of numerical computational models that estimate the ocean circulation has been constituted one of the main tools to acquire the knowledge related to space and time marine hydrodynamics variability. The Brazilian Equatorial Margin (BEM), which increased from 11 to 49 exploratory blocks in 2013 [1], has, nevertheless, recently emerged as the nation’s new frontier for this industry. Being a less studied region than those already established in the context of O&G exploration and production in Brazil, this highlights the need to further develop and organize key elements of the BEM, such as understanding of oceanic and atmospheric circulation.

With the exploration success starting in Ghana, Tano basin with the Mahogany exploration well, later to be Jubilee field, the Equatorial margin has seen significant success, but there have also been a few disappointing non-commercial and dry well results along the margins on either side. Using all data available may improve the exploration success.

The Foz de Amazonas basin has been perceived to have high potential following the French Guiana discovery at the Zaedyus field.

This paper focuses on unravelling prospectivity in two Cretaceous stratigraphic layers based upon seismic and CSEM. The lowermost plays are perceived to be the Campanian age stratigraphy of a deep marine turbidite channel/fan play in the Foz de Amazonas basin while the uppermost play is probably Maastrichtian. Leads are matured from identification on seismic sandy facies with CSEM anomalies to estimation of probable volume ranges. The interpretation of the data uses learnings from interpretation and well results in the Tano Basin in Ghana and sensitivity work from the Zaedyus work and highlights areas of possible significant prospectivity in the northwestern part of the Foz de Amazonas basin.

The deepwater Akpo field consists of multiple shale-bound sandstone reservoirs, in a setting typical of deep-water turbidite channels and lobe complexes. The target reservoir was identified and delineated by means of 3D seismic data; however, uncertainties remain about its actual thickness and internal architecture of the reservoirs. To reduce these uncertainties, and improve the understanding of the reservoir structure, multi-component inversion resistivity processing was performed on conventional Azimuthal Resistivity and Extra-Deep Azimuthal Resistivity data. Inversions showed that the wellbore initially crossed a sequence of small, isolated sand bodies with a markedly lenticular shape, bound by thick shales and interpreted as channel fills within a sedimentary environment dominated by shale deposition. As drilling progressed, the sand bodies increased in thickness and lateral continuity, while the shale intervals rapidly became thinner partitions within a massive sand-dominated body, likely consisting of amalgamated sand turbidites. The subsurface architecture mapped by the inversions appeared consistent with the interpretation of 3D seismic data. Well production data confirm that the integration of data from Logging While Drilling tools, Multi-Component While-Drilling inversions and seismic interpretation helped optimizing the well placement in a complex geological setting.

Our work presents a methodology for automated interpretation of horizons in 2D regional seismic lines, using deep learning. We use the DeepLabv3+ architecture, a convolutional neural network specialized in semantic segmentation, to segment stratigraphic regions of the seismic images and process the results to extract seismic horizons. We show results of application of this methodology in lines of the South Atlantic Austral Basin and we believe that the application of this technique is suitable for areas of recent exploration such as the equatorial margin.

In this work we demonstrate the benefits of reprocessing a legacy NATS dataset from 2014. We consider the water-bottom and the carbonate platform as the main sources of error in the imaging. The rugosity of the seafloor causes complex out-of-plane wave paths which require proper 3D algorithms, such as 3D designature and deghosting. It also causes strong multiple contamination which we address by employing a joint 3D surface related multiples elimination (SRME) and model-based water-layer demultiple (MWD) subtraction flow. The carbonate platform manifests as a strong lateral velocity variation that may cause distortion (pull-ups and push-downs) in the image. To build the model, an iterative workflow of Time-Lag Full-Waveform Inversion (TLFWI) combined with geological interpretation and ray-based tomography was applied. Finally, to overcome the azimuthal limitation of a NATS acquisition and to improve amplitude variation with offset (AVO), we applied a single-iteration Least-Squares Migration (LSM).

Over the past decades, Provenance Exploration Consultancy has developed in-house a provenance reconstruction tool, the source part of source-to-sink studies. It is an important tool in the reduction of exploration risk. It predicts the location and volume and finally, the quality of clastic reservoirs. We have successfully applied our tool in multiple exploration studies worldwide for NOC’s and IOC’s. In a nutshell Provenance Reconstruction involves detailed geological (facies), morphotectonic, drainage, denudation analyses, supported by subsurface interpretations on gravity and magnetic data, provide the framework for paleo drainage, -geological and -geographical integrated reconstructions, which ultimately provide detailed information on the petrography, mineralogy, and petrophysical properties of reservoirs. In this contribution, we will present examples of our recently completed provenance studies for Venezuela, Guyanas-Suriname, and Brazil to Argentina basins at various time slices since the Cretaceous to Recent to demonstrate how sand supply and -routes to the South American South Atlantic margin basins have changed over time.

Petroleum exploration in the Colombian Caribean relative to the Tayrona Block has been taking place since 2004 with the drilling of 4 wells and the occurrence of two gas discoveries in turbiditic sandstone reservoirs from the Lower Miocene – Upper Oligocene. The results of the molar and isotopic composition of these gases found in sandstone reservoirs suggest a biogenic origin with a predominance of isotopically light methane, with the main processes of methane formation relative to CO2 bacterial reduction. This exploratory frontier in the Offshore Colombia can host significant volumes of dry gas mainly in the Cenozoic sedimentary section (>20 TCF).