Taking an integrated approach to subsea automation

Paul Bonner, John Colpo, Jason Moody, and Steven Rogers, Honeywell, present the benefits of an integrated approach to subsea automation.

Automation systems play a vital role in delivering safe, compliant, and efficient operations in offshore oil and gas fields. As exploration and production companies enter into deeper waters, with greater distances between fields and host platforms, they are finding that discovering oil and gas can be the easy part, with the greater hurdle in moving produced fluids from reservoirs to processing facilities .


Figure 1. Automation systems play a vital role in delivering safe, compliant, and efficient operations in offshore oil and gas fields.

The offshore sector is experiencing a major evolution of both greenfield and brownfield developments, with oil and natural gas flowing from deposits that were regarded as unfeasible to tap just a few years ago. Current greenfield initiatives by oil majors involve drilling at a water depth of more than 1200 m, with many kilometres separating the platform from the subsea completion. In brownfields, exploration and production companies are tapping into new deposits and tying back to existing platforms situated over fields that have been depleted. At the same time, separation and processing operations are now being considered for installation subsea. This presents many new challenges and will result in a greater need for power and control on the ocean floor.

In addition, petroleum producers are seeking to reduce the size (and corresponding cost) of new platforms, as well as expanding existing platforms through remote subsea completions. There is also increasing usage of floating production storage and offloading (FPSO) vessels in deepwater operations. These assets are cost-effective, since they can be built remotely and are often converted from former oil tankers.

Another significant trend is the use of smarter wellheads with many more sensors and controls for performing multi-phase flow metering (MPFM) and chemical injection metering at the wellhead. This approach reduces chemical usage and can help minimise chemicals being returned in the production fluids to onshore refineries.

Modern integrated control and safety systems (ICSS), coupled with a seamless interface to the subsea equipment vendor’s master control station (MCS) can help exploration and production firms ensure continuous production and safety of operations in offshore assets.

Typical subsea equipment

A subsea production system is normally comprised of the wellhead (also known as the ‘christmas tree’) and subsea control module (SCM) or ‘pod’ containing redundant subsea electronic modules (SEMs). The SEM contains all the electronics required for control and monitoring of the tree.

Pipelines from the well to the surface are known as flow lines or risers, and multiple wells may share a common riser. Different wells may also flow to a common flow line loop. The risers terminate at boarding valves on the platform or FPSO. The boarding valve is the final isolation point before the produced oil and gas comes onboard the platform.


Figure 2. Typical subsea production operation.

Subsea control is provided by the MCS. This electronic control unit, located at the platform, employs manufacturer-specific, proprietary interfaces to communicate with the pod and manage the wells. The subsea MCS is capable of controlling multiple wells from a single location. It is typically connected to the server/subsea interface with a graphical user interface (GUI) for subsea control manipulation.

Offshore production challenges

In offshore oil and gas production, there is a focus on optimising project economics by improving operational performance, driving down production costs, and meeting completion requirements while complying with increasingly stringent regulatory standards.

Operational issues

When it comes to operational performance, exploration and production firms are challenged by the non-uniformity of suppliers providing critical subsea production equipment. Each manufacturer utilises its own tree configuration (or multiple configurations), as well as a unique pod design and associated electrical power unit (EPU) and MCS.

To further complicate matters, it is not uncommon to see exploration and production companies mix one manufacturer’s subsea tree with another manufacturer’s SCM and MCS – creating a sort of hybrid system. Sometimes there are multiple suppliers’ trees and MCSs on the same platform.

Additional problems can arise when manufacturers mandate different connection points for linking to the topside distributed control system (DCS) for subsea control. Some suppliers provide an MCS along with a subsea server employing its own proprietary GUI; communications with the DCS is often restricted to one piece of equipment or the other.

Flow assurance is a particularly important issue for subsea operators, since greater depth and pressure – coupled with longer riser lengths – require more complex and sophisticated techniques for wellhead chemical injection, slug mitigation, etc.

There is a growing need for integrated field management, whereby multiple wells with different pressures and oil and gas characteristics can be managed to maximise production. This is closely associated with techniques such as enhanced oil recovery (EOR), which make use of water or gas injection to optimise recovery.

Lastly, operators are under pressure to avoid unplanned shutdowns leading to lost production, possible well damage, and unnecessary stress on production assets.

Regulatory demands

The very nature of the subsea production environment imposes strict regulations on exploration and production firms. For instance, ISO13628-6 establishes international design standards for systems, subsystems, components and operating fluids to provide for the safe and functional control of subsea production equipment. In the Gulf of Mexico, the Bureau of Safety of Environmental Enforcement (BSEE) develops standards and regulations to enhance operational safety and environmental protection for the exploration and development of offshore oil and natural gas.

In addition, major subsea control system suppliers, topsides specialists and oil companies are collaborating through the MCS-DCS interface standardisation (MDIS) initiative. This joint industry project (JIP) is working to revise the ISO standards and implement a single, common interface with a proven and certified object library based on the OPC unified architecture (OPC UA) for subsea communications.

Completion requirements

Once drilled, subsea wells have to be completed and commissioned before handover to operations. The well being brought on must be ramped up slowly at first and then increased to maximise flow safely.

Exploration and production firms operating around the world are faced with increasingly difficult subsea completion requirements – especially on deepwater projects. This task involves the installation of the wellhead and all its controls on the seabed. In many cases, drilling new wells and adding subsea units can extend existing fields. These assets are then tied back to infrastructure such as an FPSO, collection platform or subsea pipeline.

Now, more than ever, companies involved with offshore oil and gas production need a standardised approach across manufacturers for controlling subsea equipment, as well as uniform methods for using the approved interface protocol and object library during the extended factory acceptance test (EFAT) between DCS and subsea vendors, followed by commissioning and start-up procedures.

Need for an integrated solution

Offshore automation was once a relatively customised and non-integrated process. Topside control systems were connected to a conventional subsea field, and the MCS was relied upon to maintain safe operating conditions, optimise production across the field, and effectively manage reserves. Positioned between the DCS on the platform and the subsea equipment, the MCS performed basic monitoring of sensors and control valves, interlocks, and shutdown sequences while interfacing with topsides controls.

With the expansion of subsea fields, however, there was a corresponding load increase on the legacy MCS. This required a higher-capacity platform to support larger field sizes with enhanced communications and processing capabilities. The typical MCS collects thousands of subsea data points via its communication channels, but the space allotted for its hardware is typically limited due to the tight confines on offshore facilities.

Subsea operators must make sense of a growing array of data generated from their production facilities. The ability to see, to understand, and to act on the relationships within this data is key to operational success. Effective asset management is also required to achieve daily production targets. Operators need to know how hard they can push production trains, topsides, and subsea wells without posing risks to the reservoir, the wells, and critical pieces of equipment.


Figure 3. Subsea operators are required to make sense of a growing array of data generated from their production facilities.

Minimise risk

For all subsea systems, there is a need to eliminate risk at the interface level. This can be accomplished by employing standard communication protocols such as FMC722 and Modbus TCP directly in the DCS controller. In the future, more universal protocols such as OPC UA will provide a common interface for communications between different products from different vendors. The unified, interoperable OPC architecture enables a human-machine interface (HMI) for operators utilising a standard shapes library, automation strategies based on standard control schemes, and system designs requiring a minimum amount of integration time and effort.

Reduce dependencies

In a demanding market, exploration and production companies must be able to make vendor choices to reduce risk, implement best-in-class solutions, obtain flexibility, and benefit from competition among offshore equipment suppliers. The freedom to choose the best vendor to satisfy a specific requirement also improves the ability to manage the project schedule.

Improve integration

Larger and more complex fields dictate more systems on board platforms and FPSOs, as well as on the sea floor. Operators need solutions for integrating subsea systems, topside controls, fire and gas devices, security systems, propulsion and ballast controls, and power generation and distribution systems.

The ICSS currently relies upon multiple standard protocols, such as Modbus, Profibus and DeviceNet. With an integrated ICSS approach, exploration and production companies can expect tight integration between topsides and subsea with fewer layers of complexity and equipment between them. All related equipment subsea ultimately will be an extension of the overall ICSS. Unfortunately, none of aforementioned protocols supports high-speed electrical integration or load shedding. To address this, the subsea industry is seeking technologies allowing better compliance with the ethernet-based IEC 61850 standard, which covers power control from the DCS to substation equipment. Suppliers have already developed a supervisory control and data acquisition (SCADA) interface to the DCS server based on this standard, and will soon offer controller modules to provide direct IEC 61850 and generic object oriented substation events (GOOSE) communications to intelligent electronic devices (IEDs).

Increase flexibility

As part of the evolution of subsea production, exploration and production firms are striving to accommodate more devices at the tree. For instruments such as down hole pressure and temperature (DHPT) gauges and chemical injection valves, the typical approach is to use direct, parallel communication paths tied into individual servers and GUIs at the surface. Operators are looking for solutions that can be used to transparently integrate subsea devices in the same messaging structure, and thus bring data direct to the ICSS controllers to improve operational flexibility.

Role of automation

As oil and gas companies seek ways to increase and optimise deepwater production, the technique for implementing control systems is changing – particularly how systems interface with one another. Automation systems and their interfaces are almost always on the critical path to first oil, so minimising risk through standardisation and advanced programming techniques is essential. the main automation contractor (MAC) will need to have experience in all disciplines to deliver such projects.

The role of advanced automation technology is to optimise operational and business results by increasing productivity, improving reliability, enhancing operator effectiveness, and improving lifecycle maintenance cost and efficiency.

Optimise overall performance

Fundamental to the success of any subsea development is ensuring mission-critical components work together when installed and are reliable for the duration of their service life. Integrating disparate controls utilised in production operations provides a means for operators to respond quickly to abnormal situations.

But this approach requires a single, overarching control strategy able to handle all of the automation, alarming, safety, and reporting functions for a large collection of hardware and systems designed with varying degrees of co-existence in mind.

Today’s subsea environment demands a common, highly integrated control system across multiple wells, which are often dispersed across larger and more complex fields. The system must be agnostic with regards to tree and pod vendors, and capable of tightly linking topside processing with well production. Furthermore, it should provide a single, intuitive set of operator screens – with a single look-and-feel user interface – for all connected devices.

In addition, the control solution should be configurable with a minimum number of integration points, since each interface represents an additional lifecycle cost to maintain, as well as a risk to implement and sustain.

Enable remote operations

Exploration and production organisations also require expanded remote operations/engineering and surveillance to reduce operating costs and increase the safety of employees. The objective is to monitor and manage performance, alarms, security and other parameters in real-time or near real-time, regardless of location. This capability hinges on the reduction or elimination of proprietary ‘black boxes’ such as programmable logic controllers (PLCs) and compressor/governor controls, which can be achieved by including programming for such systems in the ICSS controllers.


Figure 4. Within an integrated automation system, advanced controllers execute control strategies, interface to IO devices, and directly host custom programmable applications.

Advanced controller technology

By standardising on well-proven communication protocols and automating configuration of the subsea production system in the DCS, offshore operators can achieve a seamless interface to – and even full integration of – the MCS. This approach eliminates the need for proprietary communication protocols and also offers the advantage of built-in redundancy and reliability with the DCS for control of subsea production systems. Communications are faster and more reliable, providing access to all data generated by subsea equipment. No alarms are hidden from the operators and all alarms are managed to minimise nuisance trips and alarm floods, thereby enhancing operator effectiveness and overall safety.

Using the latest technology, exploration and production firms can support multiple MCSs, hundreds of wells and thousands of input/output (I/O) though a single controller incorporating built-in subsea communication protocols. Rather than have separate interfaces and historians, everything comes though the DCS and is easily recognised and manipulated by the operator. This compact and efficient approach minimises system hardware requirements, provides direct connectivity to subsea control units, and can be securely monitored and operated from a remote location with minimal changes to the system architecture.

Improved functionality

Within an integrated automation system, advanced controllers can execute control strategies, interface to various types of I/O devices, and directly host custom programmable applications. The controller software is key to this solution, ensuring a deterministic, consistent, and reliable control execution platform for automatic control, logic, data acquisition and calculation function blocks.


Figure 5. The value of an integrated automation solution lies in a control system that is less complex; and more compact, efficient and cost-effective.

User experience has shown that control is better at controller level than at the server level, providing faster, more redundant, and more robust and secure control of crucial operations. It also eliminates the need for servers, thus reducing the hardware footprint and saving space in cramped offshore facilities.

Enhanced connectivity

Offshore operations can now integrate their standard subsea communication protocol with the latest controllers as a native interface. This enables seamless peer-to-peer communication between topside and subsea automation assets. Communication over universally accepted TCP/IP as the media interface simplifies connectivity. Unlike server-based systems, this approach provides access to process parameters without the need for any intermediate hardware or protocol conversions, which leads to fast response, reduced downtime, and greater ease of maintenance. It also minimises the likelihood of human error with manually built interfaces, and reduces the potential for introducing those errors into communications.

With a unified topsides-subsea architecture leveraging shared communication, operators can achieve peer-to-peer orchestration of critical shutdown sequences. This means boarding valves and subsea chokes can work together for a less stressful shutdown procedure.

Less complexity

Perhaps the greatest value of an integrated automation solution lies in a simplified system with fewer layers of complexity (i.e., less potential points of failure), fewer protocols (i.e., less middleware) and fewer third-party integrators (i.e., elimination of middlemen). exploration and production firms can lower their lifecycle costs while also minimising the such aslihood of cyber intrusions. Indeed, the subsea installation simply becomes another node on the DCS system.

Conclusion

Today’s exploration and production companies must achieve a higher level of topsides-subsea integration and expand their remote operations capability. A truly integrated automation approach provides access to a wide range of process parameters without the need for costly intermediate hardware or time-consuming protocol conversions. It also ensures a common look and feel across all areas of the control system. The result is faster response, reduced downtime, and greater ease of maintenance.

This solution is not just applicable to greenfield projects; brownfield replacements with integrated technology and subsea tiebacks are feasible as well. Offshore operations can extend the life of existing assets or bring them into compliance with current control and safety standards.

By unifying process control, production and asset management, exploration and production firms can improve safety, efficiency and profitability, and reduce total cost of ownership, while achieving optimal production of oil and gas.

 

Edited for web by Cecilia Rehn

Published on 08/06/2015


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