Regularly checking your car’s fluid levels or getting your yearly health screening are two of life’s more necessary evils. Missing one or both is sure to catch up to your wallet before long, and the results are likely to be budget-busting. The same can be said for subsea wells.
While never out of mind, the trees, manifolds and more are out of sight and untouchable in their operating environment thousands of feet below water on the seabed. Inspection and intervention operations on subsea wells are expensive endeavors due to high offshore rig and tooling costs.
To keep subsea fields flowing at peak production rates, operators use a combination of good planning, constant monitoring and a lot of ingenuity. The subsea integrity management (SIM) programs that are the result of those efforts continue to evolve, much like the deepwater fields and technology they help manage.
Published in November 2014, DNV GL’s “Recommended Practice: Integrity management of subsea production systems” report defined subsea production system integrity “as both the containment of fluids and the reliable operation of safety and production equipment with the objective of ensuring both the safety and function of the installation.” Integrity of the subsea production system is established during the project phase and maintained in the operation phase and into the abandonment phase.
The report presents the integrity management process as being cyclical in nature, covering four areas: risk assessment and planning; inspection, monitoring and testing; integrity assessment; and mitigation, intervention and repair.
The more-than-50-page document serves as an in-depth guide to the establishment of a SIM program for subsea assets that operators can use to incorporate into or create their own established SIM program guidelines for new and mature fields.
The release of the guidelines demonstrates that subsea production as a technology has taken another step in an evolution that has spanned five decades, going from a novel R&D project to proven, industry-accepted technology found in the field development toolboxes of most operators around the world. The recommended practices are a formal response to the variety of concerns, observations and questions expressed as subsea technologies became more widely used.
Gaining traction, market shift
The use of subsea technologies—particularly trees—as part of the overall field development began gaining traction in the last 20 years.
According to Douglas-Westwood, there were more than 30 subsea trees installed in 1990, and almost 800 subsea trees in total had been installed up to that point.
“By 2000, the number of total installations was 1,626, and 253 were installed that year,” said Ben Wilby, a researcher for Douglas-Westwood. “Currently, we estimate that there have been more than 6,500 trees installed in total.”
But just as the subsea industry is preparing for its first foray into the world of underwater compression at Åsgard, the shift in the oil markets has created concerns regarding the impact of low oil prices on subsea development projects.
“Current oil prices will hit a number of projects—although they are more likely to be delayed rather than cancelled—as operators will need to be sure that the profit is there before sanctioning them,” Wilby said. “For projects that have already been sanctioned, we do not expect any delays or cancellations [due to the drop in oil pricing] as the capex has already been assigned to them and work has started. Deepwater is likely to be one of the hardest-hit areas. Many fields will require a high oil price—often greater than $80—just to break even.”
Overall, this will lead to a cooling off in the market, and there will be fewer contracts awarded in 2015 and into 2016 if the oil price stays low, he noted. But this doesn’t mean that projects won’t happen. He pointed to Eni’s recent award of a contract for its large Offshore Cape Three Points project in Ghana as an example.
“However, there will be fewer awards, and marginal developments will be pushed aside until they make economic sense. It is worth noting that this collapse has come just as operators were planning on cutting capex anyway, so there was likely to be a cooling off; it has just been exacerbated by the oil price collapse.
“This will likely affect frontier areas where there isn’t already established infrastructure. These sorts of fields require high capex to get off the ground and typically don’t have IOC [international oil company] support as they usually farm in at a slightly later date. The smaller operators who typically run these fields are less likely to have a good enough cash flow to justify spend on these projects.”
Setting the plan
In developing the SIM plan for its newest field—Tubular Bells—Hess Corp. drew on a number of its strengths to find the right solutions.
“Our global subsea developments group demonstrated expertise in designing, fabricating and installing the equipment,” said Jeff Wirth, director of Gulf of Mexico (GoM) assets for Hess Corp. “We leveraged this expertise and our extensive global offshore experience to develop a robust subsea integrity management plan for Tubular Bells.”
Discovered in 2003, the Hess-operated Tubular Bells deepwater oil and gas field lies in about 1,310 m (4,300 ft) of water in Mississippi Canyon Block 724. The fast-track development project was sanctioned in 2011, and first oil flowed three years later in November 2014. Net production is expected to average between 30,000 boe/d and 35,000 boe/d in 2015. Currently there are three producing wells that target reservoirs located 7,315 m (24,000 ft) below surface and 3,048 m (10,000 ft) of salt.
According to the company, the production facilities include a 15,000-psi enhanced vertical production wet-tree infrastructure tied back to a three-level topside structure supported by a classic design spar anchored by nine mooring lines.
The subsea development architecture has two drill centers connected to the three wells, a mid-field inline sled for a fourth producer and two water injection wells, two 8-in. subsea production flowlines and one 8-in. water injection line tied back to the Tubular Bells floating production system.
According to Wirth, the company’s SIM plan uses qualitative risk assessment processes to determine the likelihood and consequence of failure and to prescribe the appropriate inspection and surveillance test plans for each static component within the system. Part of this process is the review of each component’s basis of design, fabrication data, and operational and environmental parameters.
“This review allows the identification and assessment of credible damage mechanisms, causal factors and associated likelihoods of failure,” he said. “The understanding of each component’s function in relation to the delivery of safe and efficient production allows the consequences of failure to be determined by providing an appraisal of each component’s safety, environmental and production risk.”
Over the life of the field, changes that occur in reservoir conditions—like reservoir pressure decline, changes in gas-oil ratio and water cut—can have a big impact on infrastructure, according to Wirth. Planning for these changes in advance during the design stage can have a significant impact over the life of the field.
“Designs are generally optimized for early high rate of production. It can be more challenging to operate in later stages of production, where operations are usually conducted in lower pressure and higher water cut environments,” he said.
“Conversely, reservoirs that perform better than expected can result in expansion beyond what was originally envisaged, leading to more complex architecture. Our designs attempt to account for this by adding future expansion and spare capacity in systems such as control and chemical distribution to allow the upside potential to be more cost-effective and mitigate potential equipment failures. Key components may be retrievable and, depending on the design, valves or other equipment may be installed to allow replacement with minimal production impact.”
For its fields, BP looks to its Facilities Technology (FT) flagship within its Upstream Technology organization to help develop solutions for increasing production in its mature fields while also designing for the future.
“The FT group plays an important part in the design considerations and material selections at the early stages of projects. Design considerations range from production chemistry risk prediction modeling—which includes looking at all aspects of corrosion, erosion and flow assurance while taking into consideration production temperatures and pressures and even scale and asphaltene possibilities,” said Heine Gerretsen, team leader of the FT group. “We’re exploring the broader application of composite piping and continued condition monitoring of the subsea kit during its service life, assuring compliance and maintaining integrity.”
Subsea brownfield operations present a different set of challenges than the newer designed greenfields, according to Gerretsen.
“Brownfield operations require a significant amount of R&D work to develop new and innovative technologies adaptable to the existing kit,” he said. “Early projects left little to no room for adaptation of new technologies, and inspectablity of the systems was a lesser design consideration than today’s stringent requirements. Nonetheless, the integrity status needs to be known with the same rigor.”
Monitoring brings better future planning
SIM programs help operators stretch their capex and opex dollars of greenfield and brownfield projects through better scheduling of inspection, intervention and repair work, providing advance notice of needed repairs to manufacture long lead-time components and more. A robust SIM program helps to increase the level of certainty about costs associated with managing the installation, explained Alex Crossland, subsea life-cycle services business manager for Aker Solutions.
“Unplanned events and the unknown health of assets provide a high risk of significant expenditure,” he said. “One of the main drivers in our Subsea AIM [Asset Integrity Management] service is to map the health of the installation to enable more informed decisions and provide more proactive and predictable operations.”
The decisions made are based on data from the installation and reinforced with any additional insights gained from data collected from other installations.
“We have an extensive installed base of subsea control modules across the globe that generate significant amounts of subsea performance data,” he said. “By pooling this data we are able to understand the current health and then look to predict future health of the subsea systems. This transforms the conventional reactive maintenance approach into proactive and predictive maintenance, significantly increasing value to our customers.”
The performance data are combined with historical trends data to provide the Subsea AIM team the output it needs to perform additional analysis that is then shared with its clients.
“While our program is tailored specifically to the individual field, there is significant value in collating the information,” he said. “By doing so, we are able to share the learnings across our entire customer base. For example, if we identify the cause of a failure in a specific component, we are able to work with additional customers who use the same equipment and proactively take steps to manage the risk and prevent the component from failing in the future.”
FMC Technologies’ Condition and Performance Monitoring (CPM) surveillance system was the first subsea surveillance system deployed. The CPM project team brought the system online in the Gjøa Field in 2012.
“We’re looking to really help the customer minimize any downtime they might experience, and that’s where CPM comes in,” said Steve Barrett, global subsea product line director. “It starts with those data, seeing the data, monitoring the data and then having a good view of what's happening to that equipment over its entire life.”
CPM provides continuous monitoring of a subsea asset’s integrity in real time and enables early detection and diagnosis, making proactive and condition-based maintenance possible, according to the company. Advance warning of potential failures offers the potential for increasing equipment efficiency and the ability to perform planned rather than unplanned maintenance. Recognizing and understanding equipment condition based on performance trends will help avoid costly unplanned repairs, the company said.
“CPM utilizes historical data, key performance parameters and failure mode algorithms to understand exactly how the equipment is performing and predict its future performance. Access and use of the performance data is helping us optimize maintenance and uptime of the equipment,” he said.
“Anticipating problems before they start disrupting production and anticipating the level of maintenance required based on performance data are the key benefits of condition performance monitoring. Other industries have reaped huge rewards from broad applications of condition based monitoring of equipment, which is still relatively narrowly deployed in standard subsea production systems. We intend to help drive the benefits that CPM can deliver in maximizing our customer’s uptime and lowering their life of field costs.”
Advances in well inspection
At BP, new inspection and monitoring devices that assure the integrity of the subsea systems are under development by the FT group.
“From an inspection standpoint, it is crucial to understand the service-induced damage mechanisms that may be present or can occur over time and inspect for or monitor conditions to identify early warning signs of damage. From the materials point of view, the FT team strives to expand and deeply understand the safe operating envelope of materials, codifying the learnings,” Gerretsen said. “They also develop novel or alternative functional material applications to overcome production challenges.”
BP teamed with Oceaneering Asset Integrity (OAI) in the development of the first-ever subsea X-ray system that can be used to depths of some 2,200 m (~7,500 ft). The integrated system, applying GE and JME Ltd. component technologies has the capabilities of examining materials up to 9 in. of steel equivalent while maintaining a safe environment surrounding the tool, according to the company.
“Just recently the inspection team worked at NASA’s Neutral Buoyancy Lab in Houston, finalizing the systems integration testing of the new leading-edge high-energy deepwater digital radiography system. This subsea X-ray system will be used to radiograph subsea pipelines, flowlines, risers, jumper pipe and other equipment,” he said.
The X-ray system is not the first collaborative effort for the companies. BP and OAI working together have successfully developed and commercialized subsea electromagnetic acoustic transducer technology to screen long lengths of pipelines, flowlines and jumpers, identifying areas of internal damage from corrosion and erosion as well as to interrogate long-seam welds in line pipe for service-induced damage.
“The collaboration has proven to be a successful venture for the companies and equally will provide this new inspection technology to the entire offshore oil and gas industry through well-structured commercialization agreements,” Gerretsen said.
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