Integrating several imaging and modeling technologies can reduce exploration risk. Ian Bryant (Schlumberger) and Paul Xu (formerly of Ipex) present an integrated basin and petroleum system study that predicted many oil and gas accumulations in a relatively unexplored region offshore Brazil.
The study area included parts of the Potiguar and Ceará basins offshore northeast Brazil. These basins extend both on- and offshore. Onshore, the Potiguar basin is the third most productive basin in Brazil, with over 100 oil and gas fields, most discovered in the early 1980s. To date there has been sparse development in the nearshore area and none in deepwater. The adjacent Ceará basin has only four offshore fields. The geological history of the region suggests that the offshore areas of both basins are prospective targets for new hydrocarbon exploration.
Sedimentary basins with rift, sag and drift sequences formed on both sides of the South Atlantic during the Cretaceous Period when South America and Africa split apart from the Gondwana supercontinent. Onshore, the Potiguar basin formed as a result of a rift that failed to completely form. Offshore, it includes a Cretaceous rift overlain by an Upper Aptian to Tertiary sag basin. The offshore portions of Potiguar and Ceará basins are predominantly filled with clastic sediments including turbidite sequences. Basin fill also includes intrusive and extrusive rocks associated with igneous activity. The thick salt deposits common to the southern Brazilian basins are absent.
The mature source rocks for most of the known onshore fields are offshore. With burial, heat and time, these deep rocks produced hydrocarbons from kerogen contained within them. The oil and gas traversed a long migration pathway from the source kitchen to the current onshore accumulation locations. Offshore portions of the basins represent interesting exploration targets because migration pathways would have been shorter and several major northwest-southeast fault systems exist that could connect the source rocks with younger reservoir intervals. The study used a variety of modeling methodologies using existing and new types of exploration data to build knowledge about the development of the basins aimed at reducing future exploration risk.
Building a model
In 1999, WesternGeco acquired 14,000km of 2D multiclient seismic data in the deepest parts of the offshore Potiguar and Ceará basins. The dataset was processed using prestack time migration with high quality results. Seismic processing technologies are continually evolving, taking advantage of increasing computer power and new iterative interpretation and modeling workflows. Consequently, in 2008, the dataset was reprocessed using improved noise suppression, better multiple removal and prestack depth imaging techniques. A complete 3D velocity model was developed to enable efficient and consistent depth migration of the 2D lines.
The newly conditioned dataset showed improved frequency content and resolution in the shallow section and better fault and reflector definition and continuity in the deeper section compared with the original processing. This latter improvement was particularly important for exploration analysis because the deep, prerift section contains most of the source rocks in the basin. Seven wells from the shallow shelf were tied to the seismic to enable depth conversion and interpretation of eight key horizons to build a 3D geological model of both basins in Schlumberger’s Petrel E&P software platform.
The resulting earth model incorporated basin geometry from the seismic and lithologic information from the well data.
Basin and petroleum systems modeling requires reconstruction of the geological history of the basin to evaluate the maturation, migration, entrapment and preservation of hydrocarbons through geological time. Data from onshore and shelf wells provided critical information about the ability of the source rocks to generate hydrocarbons, the differences between oil families from these source rocks, and the way the mixtures of these oils can enhance the quality of the accumulations.
The geological model of the offshore portions of the Potiguar and Ceará basins was combined with geochemical data and heat flux data to build a 3D petroleum systems model. The depth-converted horizons were exported to Schlumberger’s PetroMod petroleum systems modeling application. Interpolation between the eight mapped horizons was used to generate a 28-layer model. Interpretation of the sparse well log data, together with published geological studies, enabled assignment of laterally varying, appropriate rock properties to the basin-fill.
Multiple source rocks occur in both basins, with the main source rocks occurring in the Early Cretaceous rift-filling sequences. The modeling indicated over 1700 billion barrels of oil have been generated from the source rocks present in these basins. Although the Potiguar and Ceará basins contain effective seals, they lack the thick salt deposits that characterize the Atlantic-margin basins further to the south, so trapping efficiency is lower than in the southern basins. The models suggested that less than 40 billion barrels remain in known and yet-to-be discovered accumulations.
Multiple model runs were made to assess ranges of uncertainty in the resource volumes generated. Each run generated a number of modeled accumulations that evolve through geological time. Some of these accumulations corresponded to known oil fields that are producing in the shallower parts of the basins. The close correspondence between the predicted API gravity of the oils in these forward modeled accumulations to oil gravity measured in the produced oils enhanced confidence in the model predictions.
A data-exchange plug-in for Petrel was used to bring the present-day modeled hydrocarbon accumulations back into the reference earth model, where they could be viewed in the presence of the seismic and well data. The project team then considered what more could be done to validate this forward model of the distribution of yet-to-be-discovered hydrocarbons.
Locating accumulations
The basin modeling study indicated the probable presence of mature source rocks and a charging mechanism for traps in the offshore Potiguar and Ceará basins.
Interpreted surface seismic horizons in the Petrel model indicated potentially interesting structures but not whether these structures are charged with hydrocarbons. Over oceans, remote sensing provides an independent indicator of geographic areas that may contain accumulations: naturally occurring oil seeps can be mapped using satellite images of the ocean surface. Oil on the water surface suppresses waves, and these areas reflect light differently than the typical ocean surface. By looking at results from several passes of a satellite, interpreters can eliminate short-term effects of weather or the passage of vessels, leaving persistent evidence of natural seeps. The locations of these seeps, combined with structural geological information from the seismic data, identified five target areas of the offshore basins scheduled for marine controlled source electromagnetic (CSEM) surveys that might detect resistivity anomalies in the basin-fills associated with hydrocarbon accumulations.
Surface EM surveys
Electromagnetic (EM) techniques can discriminate resistive from nonresistive bodies. Although the resistivity difference between hydrocarbons and brine is not the only contrast sensed by EM methods, a lack of resistivity contrast can be a good indicator that hydrocarbons are not present. EM acquisition and interpretation technologies have matured significantly over the past decade, and the CSEM method has been widely used to evaluate prospects when the position and depth of the target are known or at least postulated.
In the CSEM method, a low-frequency EM field is transmitted using a high-power low-frequency electric dipole antenna (source) towed behind a survey vessel within 50m to 100m of the seafloor. An array of sensitive receivers is deployed on the seafloor to measure and record the induced EM field. Transmitter and receivers are tracked and located acoustically. When data acquisition is complete, the receivers are recovered and the data downloaded and analyzed. The data are then interpreted, first in terms of electrical units and then as geologic formations taking into account and integrating other geophysical data.
Unlike natural source plane wave electrical methods such as magnetotellurics where thin resistive layers are effectively transparent, the CSEM generated dipole field interacts with such layers, and their presence, thickness, and lateral extent may be determined. As with any geophysical method, there are limitations on the depth of burial, layer thickness, and resistivity contrasts that can viably be measured.
Custom design of EM source characteristics and the geometry of the seafloor receiver array will optimize the effectiveness of the technique to meet project-specific objectives.
The Ocean EM-Connect plug-in for Petrel software was used to design CSEM studies over five areas of the Potiguar and Ceará basins.
The first step was to build a resistivity model of each of the major sequences between the mapped horizons in the basin. Each of the intervals was assigned a single laterally homogenous resistivity, and then resistive anomalies were embedded at various locations within the model.
The modeled results from various CSEM acquisition parameters were then used to evaluate the detectability of the resistive bodies and to tune parameters to obtain optimal illumination while minimizing acquisition costs.
CSEM results
The five CSEM surveys acquired in June 2009 detected subsurface resistivity anomalies in the basin-fill; however these could be related to hydrocarbon accumulations or igneous rocks. To help distinguish between these alternatives, the results from resistivity inversion and petroleum systems modeling were brought into the reference earth model. The example (shown left) shows results from one of the five surveys where the forward-modeled hydrocarbon accumulation (green) is collocated with a resistivity anomaly (yellow) detected by inversion of a CSEM survey at a point where three surface oil slicks (black dots) had been interpreted from satellite data. Adjacent indications of accumulations from the basin model did not coincide with resistivity anomalies of the same magnitude, highlighting the value of combining the basin and petroleum system modeling with assessment of resistivity.
The CSEM survey also indicated structural details missing from the 2D seismic data, which could allow further interpretation of the potential accumulation.
Conclusions
The multiclient study brought together a diverse set of data into one picture that is more informative than the individual pieces. Effective integration of the various sources of information was enabled by the Petrel environment and software plug-ins, combined with the knowledge and skills of specialist geoscientists.
The integration of seismic data, remote sensing surveys and modeling of the petroleum system provided guidance for the acquisition of several CSEM surveys. As a result of the integrated approach, the multiclient study identified several potential prospects in this relatively unexplored area. OE
Ian Bryant is currently vice president and worldwide geoscience advisor for Schlumberger Information Solutions. He has held a variety of management positions in Schlumberger, and previously worked for Shell Exploration & Production Laboratory and Shell New Zealand. He has BSc and PhD degrees in earth sciences from University of Reading, England. Bryant is a past chair of the SPE Development Geology & Geophysics Committee and an active member of SPE, SEG, AAP G and EAGE.
Paul Xu holds degrees in both analytical chemistry and computer science. He worked as a software development director at Infologic (now a part of Weatherford) for seven years. In 2004, Xu joined HRT as an IT and project manager and was named CEO of Ipex, successor of HRT & Petroleum from 2009-11. Xu currently works with HRT Oil & Gas.
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