Drilling deeper for offshore oil and gas production

Automation improvements make deep offshore drilling economically feasible, while still maintaining safety and reliability.

By Eugene Spiropoulos July 18, 2014

The quest to produce energy from increasingly remote locations has driven the adoption and evolution of advanced exploration, drilling, and production methodologies. An ever increasing amount of oil and natural gas is being produced by techniques that were once considered unconventional: tar sand extraction, fracking, and deep offshore drilling. As the value of oil and gas production has gone up and the cost of these extraction methods has gone down, the range of economically recoverable deposits has increased. This has been particularly the case with deep offshore oil and gas fields.

Drilling for oil in areas covered by water is as old as commercial oil production. Beginning with wells drilled from piers to today’s highly sophisticated floating platforms, technologies have advanced year by year. The water and rock depth penetrated have increased as new drilling methods make it possible to reach deeper deposits, and data from the U.S. Bureau of Ocean Energy Management points to more drilling in ever deeper water. While most active platforms are in relatively shallow water, the largest number of active leases and approved applications to drill are at depths greater than 1,000 m (see table).

Some of the most extreme examples of deep offshore drilling are the subsea fields off the coast of Brazil in the Santos Basin. The Lula field is already producing even though the reservoirs are below 2,000 m of water and 5,000 m of salt, sand, and rock. Estimates of recoverable oil from these deposits are around 7.5 billion barrels, but until recently, this kind of oil would have been considered impossible to exploit.

Challenges such as these would have been insurmountable before the last decades, but lessons learned and the march of automation advancements have made practical what was previously impossible: the production of fossil energy from the ocean floor, at mitigated risk to man and environment. The technologies may have changed over the past decades, but the key considerations that define the industry remain the same: safety and reliability.

Dealing with unique challenges

Several challenges arise in the deployment, successful operation, and maintenance of deep-water production assets:

• Economics of subsea and topside installations, particularly instrumentation and wiring, require precision engineering and coordination of field work as controls and communications become ever more critical.

• Operational challenges and risk amplify with increased manpower and weight of topside platforms, and with disparate and disconnected subsea and topside production systems. More equipment is being moved to the sea floor to reduce the size and weight of platforms, but this makes accessibility far more complicated.

• Safety factors are highly dependent on proper maintenance philosophy, including device statuses and performance, valve signatures, periodic testing, etc. These tasks can be costly, but failures are far more conspicuous and expensive. One only needs to consider the BP Deepwater Horizon disaster to be reminded. The visibility of operations and maintenance information is a major challenge when considering the complexity of equipment installed on the seafloor, on platforms, and onshore. Invariably, systems from several OEMs are typically involved; making collection, consolidation, and analysis of available information problematic.

• Maintaining subsea and topside assets over their operating lifespan, while allowing for optimum profitability, minimal risk, system reusability, and end-of-life decommissioning, requires management of enormous amounts of information over decades from subsea field installations. This typically includes valve activity, well performance, human activity, and much more. Historically, this has emerged as a problem equal to issues related to drilling through kilometers of material, as data management concerns have been a major roadblock to the feasibility of deeper projects.

• The cost of an abnormal situation or critical safety response involving a shutdown or subsea repair is enormous in terms of operating cost and lost production, and environmental consequences can be potentially significant. For this reason, the technology to predict, report, and respond must beat normal industry requirements for traditional land-based operations. To put the figures in perspective, the combined costs associated with a single trip, shut down, period of lost production, repair, and environmental impact from an event at a sea-floor wellhead may exceed the entire control and functional safety preventive measures project expense. This places a lot of responsibility on the shoulders of offshore operations to have all process equipment and automation and safety systems performing flawlessly.

Minimizing risks

As the amount of equipment moved to the seafloor increases, producers have to go to great lengths to minimize the risks given the enormous costs of performing even simple maintenance operations at the depths involved. Common goals include:

  • Reduce the engineering risks in terms of cost and operational errors across the whole project
  • Shorten the turnaround time to design, engineer, deploy, and commission the entire project, subsea and topside
  • Reduce the human safety and environmental risks associated with operations
  • Create engineering designs that are easy to manage and reuse so that replicating wells and other production assets can be implemented efficiently
  • Integrate disparate subsea and topside systems to present one operational and engineering interface and, very importantly, one consolidated system for data management, and
  • Capture and organize automated information from all devices, systems, and activities over the entire lifecycle of the production asset to improve operational efficiency, system reliability, operational safety, environmental risk, and profitability for the stakeholders.

Applying automation technology

Automation suppliers that compete within this demanding space must offer products and solutions that cover the entire project lifecycle from initial design phases through deployment and operation over the increasing life span of the platform. This includes many individual elements:

  • Design, engineering, and commissioning solutions for standardization, project schedule reduction, and risk management
  • Reliable core platforms for control and safety
  • Complete subsea and topside integration capable of seamlessly integrating platforms and equipment from multiple vendors into one platform for operation, safety, engineering, and information access
  • Full integration of the subsea MCS (master control station) with the TPU (topside processing unit) for control, engineering, asset maintenance, and information access functions, and
  • Field hardware and process simulation to support project phase validation, testing, and commissioning.

When considering systems from various vendors, it can be difficult to determine exactly how all these elements can be drawn together, particularly given the variety of possible combinations of configurations, equipment choices, and manufacturers. Selection criteria may hinge on previous experiences with specific companies and industry reputation. Each situation is different, but often the ability to integrate all the disparate parts into one operational whole proves to be the most critical element.

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.

Key concepts:

  • 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.

Original content can be found at Oil and Gas Engineering.