Drilling deeper for offshore oil and gas production

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


Automation helps with drilling deeper for offshore oil and gas production. Shown is the Troll C platform off the coast of Norway. July 2014 Control Engineering cover photo courtesy: Øyvind Hagen, StatoilThe 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).

While most existing active platforms are in coastal shallows, statistics point to more wells in much deeper waters.

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

The Troll C platform is off the coast of Norway. Water depth through this field is typically 300 to 350 m. Courtesy: Øyvind Hagen, StatoilSeveral 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

All automation assets, especially those deployed on the seafloor, must be monitored using an appropriate asset management platform. Courtesy: YokogawaAs 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.

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PHILIP , MD, United States, 07/23/14 10:11 AM:

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