Deep-Water Play

Key Takeaways

• Turbidite sandstone reservoirs are the dominant reservoir type in deepwater plays globally — during sea level lowstands, river systems extended to the shelf edge and delivered coarse sediment directly into submarine canyon systems, where it was transported by turbidity currents (dense, sediment-laden flows powered by gravity) to the basin floor at depths of 1,000-4,000 meters; these turbidite deposits form sheet sands (submarine fan lobes), channel fills, and slope fan complexes that have excellent reservoir quality (typical porosity 15-28%, permeability 100-5,000 mD) because they are composed of relatively clean, well-sorted sand that bypassed the shelf without the clay contamination typical of shallower near-shore sands; the geometry of turbidite systems — their distribution, connectivity, and stratigraphic architecture — is controlled by the sequence stratigraphic context and can be predicted using seismic amplitude analysis, attribute mapping, and depositional system modeling; high-amplitude seismic anomalies (bright spots) in deepwater settings are one of the most reliable direct hydrocarbon indicators in exploration, because the acoustic impedance contrast between brine-saturated sand and gas-saturated sand is large and directly visible on seismic data.
• Subsalt plays created the deepwater exploration revolution in the Gulf of Mexico — conventional seismic imaging through thick salt bodies was ineffective with early 3D seismic technology because salt's high acoustic velocity and complex geometry created severe distortion of the seismic image below the salt; when depth imaging using wave equation migration (prestack depth migration, PSDM) was developed in the early 1990s and applied to Gulf of Mexico deepwater data, it revealed for the first time the enormous Paleogene turbidite reservoirs sealed beneath salt canopies and mini-basins — fields like Thunder Horse (1.4 billion barrels), Atlantis (700 million barrels), Kaskida (3 billion barrels), and Tiber (3 billion barrels) that defined deepwater as one of the world's most prolific exploration domains; the pre-salt plays of Brazil's Santos Basin (Tupi/Lula, Libra, and associated giants exceeding 100 billion barrels of discovered resource) represent the most recent and largest expression of this deepwater subsalt concept, using the same depth imaging technology in an even more extreme exploration setting beneath the Aptian salt layer and 5,000+ meter water column.
• Deepwater infrastructure economics require large accumulations to justify the enormous development costs — developing a deepwater field requires a floating production storage and offloading vessel (FPSO) or a semi-submersible production platform (costing $1-4 billion to construct and install), a subsea production system of trees, manifolds, flowlines, and risers ($500M-$2B for a major field), and drilling and completion of multiple subsea wells (typically $50-150M per well in ultra-deep water); the resulting minimum economic field size for deepwater development is typically 150-500 million barrels of recoverable oil equivalent, which is why deepwater exploration targets large structures and plays with high proven accumulation rates; the economic threshold has driven a selection process in deepwater exploration that prioritizes high-grading the most prospective plays and largest structures, producing a portfolio of fewer but much larger opportunities than typical onshore or shallow-water exploration programs.
• Gas hydrates create a shallow hazard specific to deepwater drilling environments — in water depths greater than approximately 300-400 meters, the combination of low temperature and high pressure creates thermodynamic conditions where methane gas and water combine to form gas hydrate ice-like solids in the upper few hundred meters of seafloor sediment; this shallow hydrate zone must be carefully managed during deepwater drilling because: hydrate dissociation (triggered by heating from drilling mud circulation or well control scenarios) can release large quantities of free gas and destabilize the seafloor sediment, creating geohazards including potential wellbore collapse; gas venting from hydrate dissociation can create uncontrolled gas releases at the seafloor with well control implications; and hydrate formation in the wellbore or BOP can physically plug control systems, requiring intervention before the well can be controlled; geotechnical site surveys, geophysical bottom-simulating reflector (BSR) mapping of the hydrate stability zone, and drilling program design to manage hydrate risk are required elements of deepwater well planning in all major deepwater provinces.
• Deepwater field development increasingly relies on intelligent well completions and subsea processing to maximize recovery from expensive infrastructure — given the enormous per-well and per-facility costs of deepwater production, operators seek to maximize reservoir contact and production rate from each well and to extend facility utilization as long as possible; intelligent well completions with downhole control valves allow selective production from multiple reservoir intervals without wellbore intervention, and downhole sensors provide real-time pressure and temperature data for reservoir management; subsea processing (seabed-mounted separators, pumps, and compressors) can boost production from declining fields by reducing the backpressure on the reservoirs below what is achievable with purely surface-based processing, extending the economic life of deepwater assets by years to decades; the combination of reservoir management sophistication and subsea processing technology has allowed deepwater fields like Ekofisk and Statfjord (both starting in shallow water but using the same management principles) to produce well into their fifth and sixth decades of operation.