Drilling deeper for offshore oil and gas production
Operational integration and lifecycle
Making everything work together as one unit is the key to effective and safe day-to-day operation. Subsea and topside control interfaces must integrate seamlessly using advanced operator-centric design and operation with the core control platform. Creating consistent HMIs is critical for safety and shutdown systems so operators don't have to mentally sort through various possibilities when facing an abnormal situation.
For example, the operation to close a valve or shut off a pump has to be the same from one end of the system to the other. This calls for consistent application of high-performance graphic standards throughout. Designs based on ISA 106 serve as a basis for standardizing operating procedures and best practices for predictable and profitable activity. Alarm and abnormal event management spanning topside, subsea, and onshore systems should be based on ISA 18.2 and EEMUA191 guidelines, with automatic KPI derivation and reporting.
Safety function monitoring of ESD (emergency shutdown) systems during normal and testing operations should be determined based on LOPA (layers of protection analysis) and HAZOP (hazardous operation) analysis and safety requirements.
All automation assets, especially those deployed on the seafloor, must be monitored using an appropriate asset management platform. This includes field devices such as valves and transmitters, and also controllers and software. The ability the track the behavior and degradation of assets over time is absolutely critical to predict maintenance requirements and reduce costs of remote and inaccessible equipment.
In industrial applications it is common to talk about difficult environments, but there is little in a normal refinery that compares to operating on the seafloor. Maintaining production depends on resilient sensors and other equipment that can resist substantial pressure, which means most traditional process equipment is simply unsuitable. Likewise, hardened communication media such as subsea fiber-optic cable are needed, along with satellite communication and highly deterministic protocols-all required to handle the huge environmental obstacles related to subsea integration and production.
Key architectural elements
Control systems for offshore applications have many similarities to conventional land-based counterparts; however, additional elements are needed to support more complex installations.
The subsea MCS has to interface directly with the TPU on the platform. Given the complexity of the systems on the floor, there can be more than one control system, and multiple vendors and communication protocols may be involved. The MCS has to be able to speak all these natively so control can be fast and efficient to:
- Execute valve commands and interlocks, automatic shutdown, choke control, etc.
- Receive and monitor subsea instrument process and diagnostic data
- Monitor the subsea control module, and
- Provide HMI functions for control, alarm handling, and trending.
Design patterns for hardware and software control applications should allow a great deal of standardization and reusability. Standard field-deployed I/O and controller skids with tested, validated control layers can be used as building blocks for very reliable and highly scalable production.
Smart I/O can also provide modular design that mitigates risks related to project delays and costs resulting from late project changes and additions. The ability to use some form of smart or configurable I/O can reduce or eliminate re-engineering due to marshalling and controller loading issues.
Given the inevitability of having to integrate multiple-vendor and third-party systems, the MCS needs both basic and sophisticated integration capabilities:
- Maintain HMI and alarm philosophy consistency for topside and subsea
- Remote system access
- Instead of engineering each well individually, a modular approach can allow additional well configuration (subsea piece, topside piece, control and safety, I/O designation, third-party subsystem functions, etc.) to be accomplished via drag and drop
- Generic application programming and testing
- Design modifications and additions can be done once and applied to all, and
- High-fidelity process simulation validation of equipment and control applications.
When all these elements are working together properly, the result can be a major saving in time and cost by reducing the design, implementation, and testing phases. Once the system is built and commissioned, troubleshooting is far more straightforward with simpler change management. Systems that are functioning reliably can be replicated as new wells are added.
The future of subsea automation
Automation technologies are not standing still. Advances are bringing new capabilities that promise to expand opportunities going forward:
- Self-engineering, self-documenting systems
- Broader information standards and protocols that span production, control room, and business layers
- The IoT (Internet of Things) will offer new functionality for production and automation, allowing field devices to communicate more easily with subsea and topside systems, and with each other, and
- Greater focus on sustainability and reusability of deployed assets.
Regardless of what changes these advances bring, some elements will remain immutable: reliability and safety will not change as key design and operating parameters. Yokogawa is collaborating with our partners to bring the future of subsea a little closer to the present-day reality.
Eugene Spiropoulos is a senior technical solutions consultant for Yokogawa Corporation of America.
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Read more about offshore oil production below.
- Demands for oil production are driving exploration and drilling into deeper and more difficult offshore locations.
- Drilling and production technologies depend on automation systems that have grown in sophistication over recent years.
- Ongoing developments will make these unconventional oil sources more economical in years to come.