Salt systems, dynamics, and subsalt exploration formed one core of the papers presented at this year’s annual American Association of Petroleum Geologists meeting and exhibition.Offshore magazine was there, and the following briefly cover some of those presentations.
Subsalt in Brazil
One active and apparently huge salt play in the public eye is offshore Brazil. With reserve numbers in the billions tossed around, plenty of attention is directed toward the geology. In his paper on greater Campos basin salt sequences, Marcio R. Mello of HRT & Petroleum in Rio de Janeiro, took a look at this area.
Light oil discoveries have come regularly since pre-salt exploration began in 2005, Mello said. Geochemical and geological data, supported by 3D seismic and 3D reservoir modeling and risk assessment, suggest there are huge reserves in stromatolites and coquinas carbonate from the Lower Cretaceous pre-salt sections of the Santos, Campos, and Espírito Santo basins.
Discoveries by Petrobras in the Tupi well indicate pre-salt reservoirs of oil in place up to 10 Bbbl, Mello predicted. Also, giant light oil accumulations were reported in the pre-salt carbonates below the Marlin and in the Parque das Baleias, in the Campos basin.
The great Lagoa Feia petroleum system is sealed by a 2,000-m (6,562-ft) thick salt sequence extending up to the oceanic-continental boundary. The salt sequence is one of the most important players, Mello noted, acting not only as a seal but also to preserve the liquid phase of the hydrocarbons and the porosity of the pre-salt carbonate reservoirs.
The 3D petroleum system modeling of specific areas of the Greater Campos basin shows that the hydrocarbon potential actually is higher than that predicted because deep reservoirs, ranging from Aptian to Barremian, also exist as prospects.
—The Super Giant Great Lagoa Feia Petroleum System: the New Frontier of Exploration in the Pre-Salt Sequences of the Great Campos Basin, Brazil
Gulf of Mexico
Xavier Fort and Jean Pierre Brun of Rennes, France, did an analysis of salt flow on a regional scale in the GoM based on 3D analysis of salt structures from seismic data from Green Canyon to Walker Ridge, structural and kinematic analysis of seabed structures from multibeam data, and onshore evidence from Lidar data of active normal faulting in Louisiana and Texas.
The resulting pattern shows that salt does not flow radially directly from the coastline to the Sigsbee Escarpment, according to the authors. Rather, flow lines first converge basinward before diverging radially in the Sigsbee area. Initial and boundary conditions suitable to produce such a kinematic pattern of salt flow at basin scale were investigated using experimental models. On that basis, Fort and Brun said that a non-cylindrical pattern of subsidence likely is responsible for the kinematics and that the basal basin slope controls salt flow and associated structure development.
—Salt Flow from Basin-Scale in the Gulf of Mexico
In another presentation about the GoM, Angela Pell and Jeffrey Nunn of Louisiana State University discussed evolution of an allochthonous salt system in the southern Mars-Ursa basin.
This study indicated that a seismic stratigraphic framework and biostratigraphic markers constrained basin development and sediment accumulation from late Miocene to middle Pliocene time. External geometries for tectonostratigraphic packages were identified and combined with analyses of brittle deformation to track salt evacuation in the study area.
External geometries include wedge, layer, and trough, Pell and Nunn said. Fifty-nine faults were mapped in basin and suprasalt strata, and five phases of brittle deformation were identified. Eight evolutionary stages were identified for the time range of the study.
The minibasin previously was classified as part of a counterregional salt system. This study indicates the minibasin has experienced phases of stepped counterregional development, quiescence, and a phase of roho-style development. Thus, end-member salt system models do not account for all phases of salt evacuation.
Results indicate that salt evacuated in multiple directions through time predominately to the west. The salt system around the Mars-Ursa basin should be modeled in three dimensions. The basin has tectonic activity as the Champlain Salt undergoes reactive diapirism.
—Evolution of from Allochthonous Salt System, Southern Mars-Ursa Basin, Northern Gulf of Mexico
Another presentation offered a look at the structural evolution of the Framption anticline in the Atwater Valley fold belt. The salt-controlled Frampton anticline is part of the Atwater Valley/Southern Green Canyon frontal fold belt system in the deepwater Gulf of Mexico. A kinematic model and structural evolution of the growth fold is proposed based on the interpretation of high quality 3D depth migrated seismic data and 3D structural restoration.
Gianluca Grando, Zsolt Schleder, Ryan Shackleton, and Graham Seed of Midland Valley Exploration in Glasgow, UK, with Tim Buddin of BP Exploration, and Ken McClay of Royal Holloway University, London, said that 2D and 3D restoration frequently is used to validate structural models and to examine structural development over time. In this study, results of structural restoration were integrated with true thickness map analysis. Restoration was performed using the 4DRestore toolbox, 3D surface and volume restoration tool based on a mass-spring geophysical solver developed by Midland Valley Exploration.
Mapping and structural restoration show that small wavelength salt pillows separated by minibasins formed soon after the deposition of the Middle Jurassic Louann salt during an early contractional event. These precursor structures controlled the geometry and Tertiary folding. The main fold amplification was in the late Miocene and early Pliocene, concurrent with basal salt withdrawal and synclinal welds formation.
The authors said 3D sequential restoration techniques could be used to infer the fold kinematics for less well imaged hydrocarbon-bearing growth folds in the deepwater GoM.
—3D Structural Evolution of the Salt-Controlled Frampton Anticline, Atwater Valley Fold Belt, Deep Water Gulf of Mexico
New technologies
New and emerging technologies applied to oil and gas exploration also formed part of the news coming from the meeting. Among these were controlled source electromagnetic survey applications.
Jonny Hesthammer, Alexander Verechtchaguine, Roy Davies, Peter Gelting, Mikhail Boulaenko, and Torolf Wedberg of Rocksource ASA, Bergen, Norway, teamed to talk about a CSEM case study from the Norwegian Sea.
Controlled-source electromagnetic (CSEM) surveying is in its infancy, said the authors, and there have been several field applications cited as evidence of the technology’s shortcoming. The Luva gas discovery in the Norwegian Sea is often mentioned as a gas discovery that shows a very small and electromagnetic response despite a proven hydrocarbon column exceeding 150 m (492 ft) thick. This “false-negative” response to CSEM could have lead to the reserves being missed.
Recent advances in acquisition technology, processing algorithms, and the development of advanced workflows for integrated processing of EM and seismic data have improved the power of CSEM technology, according to the authors. In this case study, the workflow and results from reprocessing the Luva dataset not only explained the reasons for the apparent false-negative, but also showed a clearly visible EM anomaly that can be correlated with seismic results.
This study shows that CSEM data sets previously dismissed as “unresolvable” may yield valuable information, and demonstrates that the industry has yet to master CSEM technology.
—Demonstrating the Full Potential of Controlled-Source Electromagnetic (CSEM) Technology for Hydrocarbon Exploration: A Case Study of a Deep Gas Discovery from the Upper Cretaceous of the Norwegian Sea
Pre-stack depth migration technology is emerging quickly as a useful tool for figuring complex, deepwater hydrocarbon systems. Deep (25 km or 15.5 mi), large source, long offset (10 km or 6.2 mi) pre-stacked depth migrated (PSDM) seismic data is helping identify new petroleum systems, reported Steven G. Henry of Innovative Exploration Services, Al Danforth, consultant, and Sujata Venkatraman of ION. Exploration in these frontiers typically lacks well control, putting an emphasis on estimating lithologies associated with source rocks, reservoirs, and seals, and the other components needed to define an active petroleum system. PSDM data can cut risk by improving images from reflectors in areas with laterally varying velocities (salt, water bottom), to reveal faults, stratal relationships, and even hydrocarbon indicators in more correct geometric configurations.
Long (400 km dip, 2,000 km strike) regional PSDM seismic data was acquired in deepwater on the East Indian continental margin. This data imaged to over twice the depth of existing data and has higher resolution. Two examples were outlined. First is the 85E Ridge, previously thought to be a hot spot track, and now interpreted to be a continental fragment supporting a very large (50 x 100 km) carbonate platform, underlain by potential Jurassic through Cretaceous source rocks. The second example is a large deep (15-20 km) coastal graben that likely contains Albo-Aptian source rocks in the active oil generation window.
—Identifying New Petroleum Systems Using Regional PSDM Data in Deep Water East India
Sensor technology development is finding its way into exploration as part of the trend toward use of multiple types of data to improve exploration, and ultimately drilling, decisions.
New chemical-physical sensing devices offer potential to explore large offshore basins to detect microseeps and to provide molecular information indicating fluid types. These sensors, when mounted on current survey platforms, could run continuously to obtain profiles of hydrocarbons in water that can be mapped similarly to seismic, electromagnetic, and magnetic data.
Andrew Ross, Peter Eadington, Bobby Pejcic, Emma Crooke, Christopher Barton, Lech Wieczorek, Burkhard Raguse, and Mark Roberts, all of Australia’s CSIRO, reviewed available technologies and offered the results of collaborative research by CSIRO. This research focuses on two essential parts of a chemical sensing system, the nanochemical molecular binding element that is often a surface designed to be specific for certain classes of molecule, and a transduction element that provides a physical signal that binding has taken place.
—Emerging Hydrocarbon Sensor Technologies and Their Potential Use as Complimentary Exploration Devices
With the importance of subsalt exploration meeting the development of new technologies, combination of the two was sure to happen. In a presentation by Stephan Petmecky, Martin L. Albertin, and Nick L. Burke of BP Exploration, a new velocity model building method was applied to subsalt risk assessment.
Most subsalt seismic data lacks angular illumination, and low signal to noise ratios multiply the challenge, they said. Three novel techniques to build more accurate subsalt velocity models were developed. All three use geological information to constrain estimates of effective stress from which interval velocities can be derived.
De-salting simply corrects extrapolated subsalt velocities by accounting for the density differences between sediments and salt. Keeping the initially estimated subsalt pressures constant the reduction in overburden pressure, due to presence of salt, leads to an effective stress reduction which in turn lowers the originally inferred interval velocities.
Structural modeling takes advantage of the fact that anticline crests often coincide with velocity lows, while synclines relate to faster interval velocities. This is caused by lateral pressure transfer in permeable units. Overpressure estimates for potentially connected sand bodies can be used to build structural control into the subsalt stress model.
The recent discovery of a large oil reserves in deepwater GoM shows that integrating basin modeling derived effective stresses into subsalt velocity model building can reduce exploration risk. A fully calibrated 3D basin model gives an effective stress/velocity cube that can replace the original subsalt velocity field. Remigrating the seismic data gave geometrical changes in the deeper parts of the targeted prospect to reduce the initially risk. Analyzing well data from a successful exploration well confirmed that basin modeling derived subsalt velocities are more accurate than the initial model.
—New Velocity Model Building Techniques to Reduce Sub-Salt Exploration Risk
One more newer technology making waves offshore is high resolution imaging. Norman S. Neidell of N.S. Neidell & Associates, Andy Cuttel of GGS-Spectrum Inc., and Bill Kamps of Tsunami Development talked about attributes of the highest possible seismic resolution.
Holographic imaging (Huygens’ Imaging) of the earth subsurface using seismic survey data produces better spatial and time resolution than commonly used signal processing methods. For this reason it is called “high definition” imaging.
Resolution with Huygens’ Imaging gives the highest possible values with the limits imposed by imaging approximations, estimated propagation velocities, noise, and the geologic character. Such character relates to the sediment deposition and its energy, having specific expression in terms of variations over the effective Fresnel Zone and vertical grading or transitioning of the lithologies. For such imaging, illumination bandwidth is incidental and frequencies in the image domain may range between three and 10 times the input bandwidth, or even greater if geology permits.
The authors say industry should expect improved attributes and also newer attributes which relate more closely to the geology. These may include measures of depositional energy and “indices” of “correlatability” with well information.
This study presented examples of Holographic Imaging and examined a few of the basic attributes. Moving beyond the advantages of broader bandwidths for frequency and wavenumber, the study revealed improvement in velocity analyses. Faults, chimneys, and other features were seen clearly, including in many cases evidence of “wrench” character.
—Highest Possible Resolution Seismic Attributes
