Increasing Efficiency, Safer Operations Key Themes at OTC

Topics: Subsea systems Topsides/floating production systems
Don Underwood, director of subsea processing for FMC Technologies, speaking at a panel session in Houston.

Despite the downturn in the oil and gas industry, more than 68,000 experts and leaders gathered from across the world in Houston for the 2016 Offshore Technology Conference (OTC) in May. The number of attendees, from 120 countries, put this year’s OTC among the top 15 in attendance in its 48-year history.

“As it has since 1969, the world came to OTC to make critical decisions, share ideas, and develop business partnerships to meet global energy demands,” said Joe Fowler, 2016 OTC chairman. The conference included 11 panel sessions, 24 executive keynote presentations, and more than 325 technical paper presentations.

Increasing efficiency while ensuring safe operations was a key theme at this year’s conference. Sessions covered new technologies that not only reduce costs to the operator but enhance the overall safety of the operations; cost-effective advances in well cementing technologies; and use of RFID to precisely track drillpipe.

Subsea Processing

Panel sessions covered a variety of industry issues, including the value of subsea operations. Moving oil/water separation equipment from platforms to the seabed looks inevitable, but based on the current rate of adoption, it may require a long-term outlook. Out of the 5,000 wells with subsea completions, only five have used some variety of separation, whether it is separating water from oil, gas from liquids, or treating seawater before it is injected into a reservoir.

Jeff Jones, senior subsea systems consultant at ExxonMobil, talks about the company’s effort to incorporate subsea separation to make it easier to lift oil from the seafloor.

 

A panel made the case for why separators are a better option in deep water than lifting water a mile or more, processing it, and pumping it back down to the bottom for injection into the ground. “It is going to happen,” said Jeff Jones, senior subsea systems consultant for ExxonMobil. “We will get back to it.” Jones referred to subsea separation in the past tense because it has been a while since the five projects, eight if you include some smaller units used for pilots, have gone into service.

“It is not as dead as you think,” said Don Underwood, director of subsea processing for FMC Technologies. “We are in a world where, perhaps, operators cannot go forward with greenfield projects,” but still need to find ways to add production to make up for declines in older wells.

As for what will turn the inevitable technology into a practical option, the one-word answer is cost. Statoil, which has been a major supporter of moving operations subsea, has said that a 50% cost cut is needed, while Petrobras has put that number at 30%.

“There has been significant movement in that direction,” Underwood said. “For one, prices have been lowered dramatically,” while designs have shifted from huge units to “lower-cost, compact technologies” that can be added as a cheaper alternative to drilling.

“Drilling these wells will be so expensive, but tying back to existing hosts would help us squeeze every last barrel we have,” Jones said, noting that drilling costs represent 50-80% of the cost of offshore projects.

So far the company’s only experience with subsea separation is as a partner with Total on its Pazflor project off West Africa, which is operated by Total. There, gas is removed from the oil to ease lifting. But Jones said the technology could be used on its developments off Newfoundland to increase the output from tiebacks—eliminating the need to build lines to carry both water and oil as well as reducing flow assurance issues—and processing seawater used for injections to enhance production.

Removing the water and disposing it saves the cost of lifting water, which is then pumped back down to the bottom to be injected into the formation. As fields age, and when the water cut far exceeds the oil, operators must either expand processing capacity on the platform or live with limited output.

“Adding a pump is sometimes not the most efficient answer, but it is easier,” Jones said, noting that the comfort factor exceeded the energy required to pump water to the surface, process it, and send it back down.

Turning subsea separation into a tool used as widely as pumps will require executives to show their support for doing something new, and make it clear that project managers are not risking their career if they choose to use subsea processing.

The heightened attention on the risk of using subsea processes may be adding to the complexity, which is an obstacle to adoption. One of the toughest challenges is removing sand from the production stream because it can shorten the life of these devices. But that could introduce the complexity-driven risks.

“If a pump can, in theory, fail because of sand, we create a sand system that is 10 times more complicated than the pump,” said Rune Fantoft, chief executive officer of Fjords Processing, a Norwegian firm working on separation. While he recognized the need for improved equipment to deal with such problems, he pointed out the methods are likely to be drawn from what is now down above the surface.

FMC has addressed one of the problems nagging subsea operators—the hard-to-separate emulsions of water and oil that stymie processes—with its InLine ElectroCoalescer, which earned it an OTC Spotlight on New Technology Award. The device uses electrical currents to cause oil to form droplets that can be easily removed from water. It is not a new idea, but it is a compact solution to emulsions, which separation methods using forces such as gravity cannot solve. “You cannot depend on separation for that,” Underwood said. “Emulsions could take days to break down on their own.”

The industry needs to create other compact, standard models that can be added as needed to increase processing capacity, according to the panel. But, so far, the experience of the five projects shows subsea processing methods work.

Reducing Project Complexity

Complexity is the central challenge of executing deepwater major capital projects, and the industry must find ways to reduce it for future projects to be viable, Chevron’s General Manager of Facilities Engineering Mick Kraly told a luncheon audience during the conference. “Major Capital Projects Yesterday, Today, and Tomorrow: Is There a Need for Change?” was his topic.

Kraly said companies must prove capable of finding, developing, and maintaining the competencies needed to carry out these projects and overcoming various performance gaps that have become increasingly evident. The industry must commit to increasing standardization across multiple projects, come together to address major technological challenges, and take full advantage of joint industry projects and the work of industry committees, he said.

Deepwater projects are inherently complex because of the increased reservoir recovery necessary to justify their economics. “We’ve got to have the ability to do further technology deployments to be successful,” Kraly said. Projects involve seafloor pumps, may also use in-well and electrical submersible pumps, and can incorporate waterflooding, which may be followed by enhanced oil recovery. “Each of these adds a layer of complexity,” he said.

Kraly presented a major consultant’s analysis of a large number of deepwater installations that showed widespread performance gaps in the industry’s project executions in the areas of meeting schedules, keeping within budgeted costs, and attaining targeted startup production. Only 18% of projects met both their schedule and cost goals, and a mere 8% met schedule, cost, and production attainment goals. “If we don’t change, obviously in this low-price environment many projects are not going to be viable,” Kraly said.

At the same time, the necessary technical capabilities for these major projects are not always available to the extent desired. Chevron is addressing these needs internally with a focus on three areas:

Increasing the industry standardization of future projects is critical to their successful execution, Kraly said. “We try to simplify processes, workflow processes as well as engineering standards as well as executional standards,” he said. “We are challenging ourselves to stop doing this on an ad hoc basis and actually implement these as part of our overall work stream. We have to take advantage of standardization in the ability to deliver things more repeatedly as well as more cost-effectively.”

He recommended that companies across the upstream industry and regulators work together to enable the industry to move forward, and cited high-pressure/high-temperature (HP/HT) technology as an area that could benefit especially from such an initiative.

Recent discoveries in the Gulf of Mexico present downhole environments that will exceed the current 15,000-psi limits of wellheads, casing liners, and blowout preventers, and new HP/HT technologies must be developed and qualified to operate in 20,000-psi settings. International oil companies, EPC contractors, suppliers, and regulators are sounding the same message for this need.

“Let’s do this together,” Kraly said. “Let’s just make sure that we have these controls and standards and qualifications. Let’s make sure that the 20,000-psi opportunities are done in the best way.”

Cost Savings for FPSOs

With the oil and gas industry facing an uncertain financial future, organizations are looking for any way to save costs. One way to achieve cost savings is through efficient planning in the construction and conversion of floating production, storage, and offloading (FPSO) units. In a technical session, “Practical Steps Toward FPSO Cost Reduction,” a series of industry experts discussed the strategies organizations may take.

Bryan Kendig outlined the opportunities organizations have to lower costs in purchasing oil and gas production equipment and services for major offshore projects as described in OTC paper 27009. Kendig is a supply chain manager at SBM Offshore. In the paper, Kendig and co-author Jim Wodehouse, vice president of technology management at SBM Offshore, recommended strategies organizations should take to maximize cost reductions on future projects.

One recommendation is to use the procurement department in a strategic manner. Kendig and Wodehouse said organizations should devote a sufficient internal budget that is independent of a client’s project budget so that procurement methodologies can be developed and implemented.

Other recommendations focus on standardization. Kendig and Wodehouse suggested that the standardization of equipment, specifications, documentation, and working processes are good economic practices, and organizations should utilize them on offshore projects. They also recommended that any major cost reduction decisions with regards to equipment or key vendors should be made in a collaborative fashion, with a team of stakeholders representing an appropriate cross-section of functions within the organization.

Kendig said vendors should play a critical role in identifying cost-reduction opportunities. However, he also described the process of working with equipment vendors as “scattered” and that it is not realistic for companies to expect vendors to reduce their budgets by significant margins.

“Energy is feeling a transition, especially offshore,” he said. “We’re the first ones to feel the brunt. But, some of our vendors are catering to other markets, so the 50% reduction isn’t there for those vendors. I can tell you from previous experience putting together proposals that it’s been a long time since I’ve seen gross margins from vendors that were more than 20%.”

Technology development was another focus of Kendig’s presentation. In their paper, the authors recommend that project developers, vendors, and EPC contractors should collaborate to identify and develop the technologies that will lead to cost reductions prior to the awarding of the EPC contract.

Kendig said he wants to see the industry approach cost reduction in the same manner in which it approaches technology development. He suggested the development of a joint-industry program targeting things like the creation of standards for documentation and certification.

“I am very passionate about improving costs and seeing what we can do within the industry from a supply chain perspective,” he said. “Let’s pull some things out we can repeat from one project to the next project. I would really like to see this stick to the wall. I’ve been in the industry for 27 years. I’ve seen the ups and the downs. The ups come around, and we tend to forget the things we were trying to do [during the down periods].”

Kendig was one of seven speakers to present a paper at the technical session. In another presentation, Kees van Roosmalen, a managing director at Nevesbu, discussed the lessons learned from his company’s experiences engineering FPSO conversions. In OTC paper 27053, van Roosmalen said thorough preparation is key to cost-effective ship conversion.

“FPSO conversion requires that you know what you’re going to do when you start doing it,” van Roosmalen said. “You need to have phased growth. You need to know what you’re going to do in what sequence. You need to have good preparation and good [front-end engineering design]. You need to manage your subcontractors and vendors because many of them are delivering projects tailored to the FPSO you are looking at.”

JPT staff Stephen Rassenfoss, Trent Jacobs, Joel Parshall, and Stephen Whitfield contributed to this report.

Increasing Efficiency, Safer Operations Key Themes at OTC

01 July 2016

Volume: 68 | Issue: 7