The price of oil struggles to rally, and operators continue to face cost pressures. Subsea processing equipment provides alternative solutions to traditional oil recovery methods. The technology and the manufacturer's experience deploying it can play an important role in helping operators reduce their capital (CAPEX) and operating expenditures (OPEX). Minimizing the interfaces between the pump motor unit, power system, subsea power distribution, and integrated power and control umbilical is one of the solutions being implemented in subsea and deepwater environments. This configuration's goal is to optimize the subsea packaging of these elements alongside the manifold and the subsea control system.
Options for Optimization
By having all these building blocks in one engineering, procurement and construction (EPC) work package, exploring trade-off scenarios is possible. For example, rather than having two, single-bore flow-line connectors between the pump module and manifold, a single, multi-bore connector could be used. Similarly, where currently one chemical injection line is in the pump module and several are in the pump station, potential alternatives may be to include one set of injection points or to reduce the number of injection lines. Securing these changes could affect the whole system, resulting in fewer tubes in the umbilical and less hardware topside for chemical delivery. In addition, flowmeters on the boosting station could be reconfigured to reduce the number of connectors and modules, while pumps and retrievable modules could be optimized in ways that lead to faster turnarounds in operations and maintenance. Any focus on minimizing operating costs should include reducing the power required in the subsea boosting stations. A permanent magnet motor may help lower power consumption. Optimizing the design of the umbilical and variable frequency drive (VFD) topside can decrease overall power consumed. In general, changes made at the front end can have a significant impact on OPEX, affecting costs from power and chemical consumption to intervention. These up-front considerations include condition monitoring. Condition performance monitoring should cover the entire boosting station, including the pump and motor. This helps operators plan for more timely and effective interventions. Similarly, the creation of retrievable modules that can be maintained by a light intervention vessel rather than a large construction vessel allows for further savings.
Multiple Subsea Pump Options
Advancements in new pumps provide new opportunities, including increased flexibility for operators. Many operate in the most severe conditions, and operators can control this equipment from as far away as 18 miles (30 kilometers). To help control costs, new pump designs are often standardized, using the same concept as a predecessor, although specific changes have been made to address the high pressure/high temperature challenges of up to 15,000 psi, 350 F and a 3,000-meter water depth. For all companies designing pumping systems, partnering with operators and end users as early as possible is critical to solve the challenges they will face in the field. All operators experience distinctive circumstances on the seabed because each reservoir has unique properties. That makes engaging with them up-front vital so challenges can be understood and tackled from the outset. Equally important is focused response to the operators and end users—pre- and aftermarket. One end user may require a 3.2-megawatt (MW) motor, but the market demands a broader range of sizes. In parallel, exploration discoveries and developments are increasingly deeper, colder and have longer step-out distances, which will require a 15,000-psi, 6-MW motor, currently under development.
A 6-MW pump may provide a solution to the trade-off between using downhole electric submersible pumps (ESPs) and seabed pumps. A design using a 6-MW, seabed pump may mean a higher initial CAPEX. However, when compared with full-field development costs, the seabed pump system is a more cost-effective and value-adding solution than a 3-MW pump on the sea floor and an ESP downhole. The higher MW setup means that only one piece of subsea equipment must be maintained instead of two pumps in series, which helps availability and reduces the need for regular costly interventions on a downhole ESP.
Industry Partnership Benefits
Joint ventures between oilfield equipment and instrumentation and gauge providers offer opportunities for integration between subsea production and processing systems and the subsea umbilicals, risers and flow lines (SURF) package. These ventures have many advantages, such as the reduction of cycle times, project management and project-related costs. Similarly, significant savings from more seamless integration of technologies and hardware are possible. Traditionally, a subsea processing station, when designed, has been isolated from the SURF scope. Now, more integration and consideration of technical and overall field optimization are possible. In the case of large field developments, examining the trade-offs between boosting at the drill centers and the riser base and other alternative field development concepts is possible. Consideration can also be given to the cost of the following:
- Flow lines
- Termination assemblies
- System types
- Power distribution systems
Considering all these components allows all parties to assess the value proposition for the operator, total system CAPEX and OPEX, and the route that results in the highest increased recovery and value.
Any equipment manufacturer's or service provider's ultimate goal is to address operators' short- and medium-term priorities and to design with these priorities in mind so that the efficiencies relating to CAPEX and OPEX can be maintained. Controlling costs is one thing, but emerging on the other side of this market correction with differentiated products that add even more value is vital.