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Floating production systems

The Future of Floating Production Systems

The complete paper provides insight on the commercial drivers that significantly changed floating-production-system (FPS) design philosophy after 2014, with a particular focus on the US Gulf of Mexico (GOM).

The complete paper provides insight on the commercial drivers that significantly changed floating-production-system (FPS) design philosophy after 2014, with a particular focus on the US Gulf of Mexico (GOM). The paper explores near-term and longer-term outlooks for FPS design, touching on technology and automation that can relocate staff onshore to increase safety, reduce capital expenditure (CAPEX) and operating expenses (OPEX), and increase return on investment (ROI). The authors note that the commercial analyses presented in the paper are indicative and are subject to revision.

Introduction

The drastic fall of oil prices in late 2014 forced a harsh but necessary overhaul to the design philosophy of deepwater projects. Bigger was no longer better; the industry set to work using methods such as lean design and standardization for commercial improvement. Through a slow recovery in commodity prices and a steady persistence in innovating and implementing improvements, the deepwater sector made significant strides in commercial and operational efficiency.

This overhaul was a rough 4-year journey as investment capital, and even some operators, retreated from deep water for lower-cost and faster-cycle onshore projects—at least, that was the perception at the time. Deepwater projects were delayed or canceled, and the industry saw consolidation among operators and the service sector. While the period may have been uncomfortable, it was a much-needed turnaround for an industry with average breakeven costs at $70 per barrel. The rework resulted in an industry fit to compete with onshore production, with breakeven costs reduced by half in some cases. Five primary variables exist with regard to net present value (NPV), and breakeven calculations are based upon them: • Commodity prices • Reservoir performance • Upfront costs (CAPEX) • Time value of money between investment and cash flow (project cycle time) • Ongoing operations and maintenance costs (OPEX) Commodity prices are outside a team’s control, and reservoir performance is a technical risk that must be managed throughout the life of the field. CAPEX, OPEX, and project cycle time can be controlled from the start, when management teams are facing pre-final-investment-decision stage gates and are perhaps the most effective levers available to influence a project’s economic success. The complete paper explores key changes in FPS design that led to reduced costs, shortened cycle times, increased optionality, and improved ROI. Appomattox to Vito Shell sanctioned the Appomattox project in mid-2015 with a platform production capacity of 175,000 B/D and one of the largest weight displacements in the GOM. Capacity was planned to increase In Q4 2019 to 250,000 B/D, placing the project next to Thunder Horse as the largest throughput capacity in the GOM. Appomattox may be the last such monster platform seen in the region. Vito was not far behind Appomattox per the original plan, but became a ­project that saw a significant (approximately 3-year) delay for a redesign from the subsurface up, driven by the downturn. The result was that Shell set a new bar for standalone projects, with a breakeven price expected to come in at$30/bbl. This was achieved by a reduction in well count, improvements in drilling efficiency, implementation of a unique contracting strategy, and lean design of the FPS. The authors estimate the cost of the FPS was reduced by a third, from $1.5 to$1 billion.

The redesign focused on minimum viable product, with a reduced production capacity and replacement of a gas-recycle system with gas lift, which reduced topside size and steel, a primary driver of cost. Whether simply by the nature of a smaller facility or by implementing automation technology, a reduction in personnel on board also reduced operating costs significantly. Fig. 1 shows the change in Vito cash flow as a result of the 3-year redesign and CAPEX and OPEX reduction.

Embracing a New Model—With Options

Optionality is a powerful lever for commodity price and reservoir performance—not in terms of controlling them, but rather responding to them. Operators can build optionality through phased development; hub-and-spoke development; multiple platform options; and, in the long term, unmanned production systems.

At the time of writing, Anchor was the most recent standalone project to be sanctioned in the GOM. It is the first-ever ultrahigh-pressure field (20,000‑psi operating pressure) to reach sanction. It is designed with optionality in the form of a phased development. The initial phase targets the southern fault block of the reservoir. The second phase, if sanctioned, would target the northern fault block with a new four-well drill center. The performance of the southern wells will inform the decision to move forward with the next phase.

Perhaps the most well-known form of optionality is the hub-and-spoke model. These platform designs use topside and subsea technology that has been standardized to the level of commoditization. Multiple participants invest in the facility, reducing the upfront CAPEX load and improving economics for fields that might be marginally commercial otherwise. These facilities are designed with spare capacity to allow for future tiebacks as they are discovered or reprocessed.

The authors expect that Shenandoah will follow Anchor as the next ultrahigh-pressure field to reach sanction, with even more optionality built into the model. A hub-and-spoke platform at Shenandoah could serve nearby discoveries such as Yucatan, Coronado, and even more exploration targets in the area.

Optionality can include multiple platform options. A design concept for LLOG Exploration’s Moccasin discovery has long been a daisy-chain to Buckskin, which currently has two producing wells, to Occidental’s Lucius platform. However, early production from Buckskin has met or even exceeded expectations and exceeded Buckskin’s allotted production handling agreement throughput. Ramping production at Lucius and development plans for new wells could require Buckskin to choke production and delay development of the remaining six wells planned. One alternative could be to codevelop Moccasin and Leon with a new platform and reverse the direction of the daisy chain from future Buckskin wells to Moccasin and to the hypothetical new platform.

In oil and gas development, lifting, separating, and transporting remain the core tasks. However, by some estimates, 70% of the weight of an FPS is dedicated not to supporting the core tasks, but to supporting the safety and comfort of humans with accommodations, fire pumps and blast walls, potable water systems, and the like. Reducing CAPEX by removing equipment should easily offset the cost associated with automated or remotely operated production systems.

The next generation of unmanned hub-and-spoke projects is already being tested in the North Sea. Equinor’s Oseberg H is an unmanned fixed platform located 5 miles from the manned host facility. It is effectively a tieback, but not subsea, with access to some of the equipment on the fixed platform.

In the GOM, high-impact new platforms are floaters, with the regulatory requirement that there be a minimum of 11 personnel on board a floating vessel. While this requirement may not change, the floating facility can change. The concept of processing and transporting directly from the seafloor is also being studied by Equinor and could make the floating processing unit a thing of the past. Remote operations of this magnitude would eliminate the challenge of longer subsea tiebacks because it could effectively reduce length to that of a jumper and change everything beyond the subsea host to midstream infrastructure.

The challenge of real-time, remote operations and automation will be enabled by emerging connectivity technologies. These connections must be highly dependable to meet the safety standards of the deepwater industry, ensuring immediate information transfer to operators for human decision or automated response when appropriate. Another enabler will be all-electric, onsite power generation or power from shore, which requires long-distance, stable power transportation. Replacement of turbine- or engine-driven pumps and the removal of fuel-handling systems and hydraulics will improve reliability significantly and reduce maintenance requirements.

Conclusions

The role of the deepwater innovator today must be that of an advocate, collaborator, and integrator. The industry must embrace a renewed strategy of education and advocacy about the significant role that deepwater will continue to play for years to come. It would be inefficient for deepwater engineers to write new automation code from scratch when others have made significant strides. The industry will need to rely on the telecommunications industry for new technologies to enable dependable remote operations. Collaboration with those outside the industry will be necessary to advance these technologies and integrate them as purpose-built.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30715, “Floating Production Systems: What’s Next?” by William Judson Turner, SPE, Welligence Energy Analytics, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission.