Vast hydrocarbon deposits await discovery and development in deepwater basins around the world. As an industry, we are challenged to profitably recover these resources while dealing with the price volatility of the commodity that drives our fortunes.
We have made amazing strides toward this end in the past decade. The fact remains that the business of deepwater development is complex and continuously evolving, Capital outlays are large and consequences of failure severe.
Step changes in subsurface and drilling technology have enabled us to find and characterize reservoirs with greater certainty, then recover more hydrocarbons with fewer wells in increasingly deeper water.
The other challenge we confront is the continuous reduction in costs and cycle time to first oil or gas for field development infrastructure above the mud line in locations that are progressively deeper and more remote.
In a recent survey, operators with extensive deepwater portfolios identified field development system selection, project execution, technology development, and quality teams as critical success factors for profitable development. An underlying premise was that there was to be no compromise in health, safety, and environment, or in effective management of risk.
The process of matching the field development scheme to the reservoir and site characteristics is a critical and daunting task, yet fundamental for ensuring success. Ironically, pressures to accelerate developments have pushed many project teams to limiting or skipping this process.
There are a large number of variables involved in the decision-making requiring highly skilled, culturally diverse, multi-disciplinary teams. Unfortunately, there is a relative dearth and availability of quality project performance data and benchmarks, and no simple road map to get us there.
Industry has successfully developed both "wet" and "dry" tree solutions, considered reasonably mature in up to 5,000 ft, that offer flexibility in tackling developments. An analysis of various deepwater projects installed worldwide reveals no clear relationship or trend between capital cost per BOE produced and water depth or field size, whether they were subsea tiebacks, spars, tension leg platforms, floating production, storage, and offloading (FPSO) units, or semisubmersible platforms.
In the survey, operators indicated that a majority would pick the option that best fits field characteristics, but having done so, would choose field-proven designs to reduce risk and cycle time. Companies place a high value on standardized facilities, but are pragmatic in recognizing that one size or concept will not fit all situations.
Over 80% of discovered deepwater fields have reserves of 100 million BOE or less, a majority of which are, or will be, developed as subsea tiebacks to existing or new production hubs. Recognizing that the key to expanding the commercial envelope of future deepwater reserves is to reliably increase step-out distances, industry is devoting significant resources to developing enabling technologies in this area.
Wet and dry tree production hubs will continue to anchor future developments. Operators tend to prefer dry tree solutions to develop complex reservoirs, requiring frequent well intervention and that can largely be depleted from a single drill center. Technical issues and high costs of extending dry tree platform production risers beyond 5,000 ft will require breakthrough technologies. Wet tree platforms offer greater flexibility to well count and transparency to water depth, and will require extensions of current technology to enable production in 10,000 ft. Many operators believe that future ultra-deepwater developments will utilize subsea trees.
Operators place a higher value on proven execution capability than proven technology. Consider that FPSOs, regarded as the most mature deepwater production technology, continue to experience unwelcome surprises ascribed to a combination of poor execution and aggressive scheduling.
Predictability of cost, schedule, and quality of delivered product is more important than low cost. Some operators have realized significant reductions in cost and cycle time by systematically employing a strategy of repetition, refinement, continuity of project and contractor teams, and effective transfer of lessons learned. Operators apparently place a high premium on contractors with experience and track records, and quality of personnel on project teams was critical in contractor selection and project success.
Reducing costs in ultra-deepwater will require technology development. It is important to focus on those technology's that will provide the biggest bang for the buck. System and value engineering processes have identified high impact technologies. Not surprisingly, subsea and downhole technologies offer greatest opportunities for increasing recovery, operability, and extending tieback distances.
It typically takes 5-10 years and big dollars for breakthrough technologies to progress from incubation to application. Those also come with the greatest risk of failure. As an industry, we have continually struggled to find ways to consistently and reliably fund such efforts while dealing with oil price volatility.
No discussion of deepwater challenges would be complete without the obligatory gnashing of teeth over the shortage of skilled people. Successful implementation of system selection, project execution or technology development is unattainable without a critical mass of high caliber experienced teams. Presently the supply and demand equation in seriously out of kilter. I submit that this gap poses our greatest challenge to future deepwater developments. As an industry we have failed miserably in the retention, recruitment, and training of needed skill sets. We have pontificated about the problem for years, but done little about it. Those that have, and are, will reap the benefits.
Vice President, Offshore Technology
Kellogg Brown & Root