Deepwater Oil Exploration and Development

Filling out explanation from Texas Oil Man. You can find him on X. All errors MINE.

Phase 1: Initial Exploration (1-3+ years, $25-30 million)

  • Target selection
  • Lease sale acquisition
  • 3D seismic data collection
    • Seismic surveys can cost upwards of $200,000 per day
  • During this phase, only preliminary work is being done to identify potential drilling locations. The majority of exploration capital is considered “at risk”—up to 90% of explored prospects may not be commercially viable.
  • Geopolitical Sensitivities: Exploration leases in disputed or environmentally sensitive waters (e.g., the Arctic, South China Sea) can trigger diplomatic tensions or environmental activism, delaying projects.

Phase 2: Exploration Drilling (2-4 years, Many millions of dollars)

  • Mobilization of Mobile Offshore Drilling Unit (MODU)
    • Typically Generation 6 or higher Semisubmersible or Drill Ship
    • Selection depends on drilling requirements, rig availability, and schedule
    • Rig Day Rates: Day rates for ultra-deepwater drillships have exceeded $400,000/day in peak markets (e.g., 2013–2014), driving up exploration costs significantly.
  • Drilling multiple exploration wells and possible sidetracks
    • Exploratory wells can cost $25 million to over $100 million for deep water prospects
  • Refining the subsurface picture
  • Conducting technical and economic evaluations
  • Working toward Funding Investment Decision (FID)
  • Costs at this stage primarily include:
    • Exploration wells
    • Consumables
    • Staff time for planning and vendor consultations
  • Notable Drillship: The Deepwater Horizon—though infamous—was among the most advanced rigs of its time and symbolic of the risks inherent in this phase.

Phase 3: Field Development Planning (Prior to FID)

  • Determining production solutions
  • Evaluating pipeline options (existing ullage vs. new pipelines)
  • Equipment manufacturing timelines
  • Development of production profiles
  • Planning for future workovers and interventions
  • Forecasting through field abandonment and asset recovery
  • Hundreds of staff involved in planning process
  • Culminates in rigorous FID approval process

Phase 4: Field Development Implementation (1-5 years, $300M to $10B)

  • Timeline varies based on development solution:
    • Shorter timeline (1-3 years) for subsea tiebacks
    • Longer timeline (3-5 years) for floating hosts (FPSO, SPAR, TLP)
  • Lower costs (~$300M) for subsea tieback solutions
  • Higher costs ($5-10B) for floating host solutions
  • Activities include:
    • Manufacturing of all equipment (first steel cut)
    • Producing control lines, umbilicals, flowlines
    • Drilling top-holes or production wells
    • Installation of infrastructure
    • Implementation of planned workovers
    • Statistical interventions
  • First Steel Cut: A key milestone, often marked by media coverage, signaling the beginning of tangible field development after years of planning.Crew Logistics: For floating production units, support crews rotate in 21- to 28-day cycles, often via helicopter, which requires detailed planning and safety protocols.Local Content Requirements: In regions like Brazil and Nigeria, laws mandate use of local labor and suppliers—this can lengthen timelines but also support domestic growth.

Completed Deepwater Projects

Independence Hub (Anadarko)

  • Natural gas facility in 8,000 feet of water, 120 miles from Mississippi
  • Lease purchased: December 2001
  • First exploratory well: 2003
  • First production: mid-2007
  • Total timeline: ~5.5 years from lease to production
  • Was one of the largest capacity deepwater gas processing facilities when completed

Perdido (Shell, Chevron, BP)

  • Located in Alaminos Canyon area, Gulf of Mexico
  • Water depth: 8,000 feet (2,438 meters)
  • Construction period: Spar hull constructed in Finland and shipped to Gulf in 2008
  • First production: 2010
  • Design capacity: 130,000 barrels of oil equivalent per day
  • Total development timeline: ~6-7 years
  • Ownership: Shell (35%, operator), Chevron (37.5%), BP (27.5%)
  • One of the deepest offshore oil and gas facilities in the world

Thunder Horse (BP)

  • Located in Mississippi Canyon blocks, Gulf of Mexico
  • Water depth: ~6,000 feet
  • Originally scheduled to begin production in 2005
  • Delayed by hurricane damage and technical issues
  • Actually came online in 2008
  • Production capacity: 265,000 barrels of oil per day and 200 million cubic feet of gas
  • Became the second largest oil producing field in North America at startup
  • Ownership: BP (75%), ExxonMobil (25%)

Atlantis (BP)

  • Located 240km south of New Orleans in the Gulf of Mexico
  • Water depth: 7,074 feet
  • Originally scheduled to start in 2006
  • Delayed by hurricanes in 2005
  • Phase one production began in 2007
  • Phase three expansion completed in August 2020 ($1.3 billion)
  • Current production capacity increased to 36,000 barrels per day
  • Ownership: BP (56%), Woodside (44%, formerly BHP)

Egina (TotalEnergies)

  • Location: Offshore Nigeria, 1,600 meters deep
  • First oil: December 2018
  • FPSO construction involved over 200 local suppliers
  • Production capacity: 200,000 barrels/day
  • Cost: Estimated $16 billion—among the most expensive deepwater developments

Lula Field (Petrobras, Brazil)

  • Formerly called Tupi; first major discovery in Brazil’s pre-salt layer
  • First oil: 2010; development ongoing
  • Required ultra-deep drilling through 2,000 meters of salt layer
  • Helped make Brazil nearly energy self-sufficient in the 2010s
  • One of the largest discoveries of the 21st century

Key Considerations

  • The entire process can span multiple U.S. presidential administrations
  • Changes in administration can bring shifts in oil policy
  • Inconsistent government messaging creates significant hurdles for long-term planning
  • Capital intensiveness increases dramatically after FID
  • Ultimate goal is to access millions to billions of barrels of reserves
  • Deepwater investments decreased from $335 billion in 2014 to $160 billion in 2017 due to oil price decline
  • Recent recovery in oil prices has led to renewed interest in deepwater development
  • Decommissioning Costs: Decommissioning deepwater assets can exceed $100 million per well—an often underappreciated lifecycle cost.
  • Carbon Footprint: While lower than oil sands, deepwater production has a higher emissions profile than onshore shale due to long supply chains and energy-intensive logistics.
  • Global Shift: As of 2023, Brazil, Guyana, and Namibia have become new deepwater hotspots, shifting global exploration away from traditional basins like the Gulf of Mexico.
  • Digital Infrastructure: Many modern platforms are fully digitized, enabling remote operations and predictive maintenance using AI and IoT.

DEFINITIONS

A subsea tieback is an oil and gas development method where underwater wellheads on the ocean floor are connected (“tied back”) to an existing production facility via pipelines and control systems, rather than building a new standalone platform.

These underwater wells are typically connected to a manifold system on the seabed, which then connects through flowlines and umbilicals to either an existing offshore platform, floating production system, or sometimes directly to an onshore facility.

The main advantages of subsea tiebacks include:

  1. Cost efficiency – They’re much less expensive ($300M range) compared to building new floating production facilities ($5-10B)
  2. Faster development time – Can be completed in 1-3 years versus 3-5+ years for new platforms
  3. Ability to develop smaller fields – Makes otherwise uneconomical discoveries viable
  4. Extended reach – Can access reservoirs located many miles from existing infrastructure

Subsea tiebacks are particularly valuable for developing smaller satellite fields near existing infrastructure, extending the productive life of mature basins, or as an initial development phase before potentially installing dedicated facilities if production warrants it.