How Enpro Subsea helped one operator to reach first oil in just 12 months
June 3, 2017
Enpro Subsea discusses its ESSI FAM system, and how it has helped one operator to reach first oil in just 12 months
In an age of constant cost pressures, equipment suppliers and service firms are being asked to push the envelope continually. In the subsea sector, increasing standardisation and a focus on more plug-and-play solutions have been key drivers to achieving this but the pressure is still on to work more efficiently and effectively.
One firm leading the way in this open approach is production optimisation specialist Enpro Subsea. The company’s proprietary Enhanced Subsea Sampling & Injection (ESSI) and Flow Access Module (FAM) systems offer support for a wide range of production issues throughout field life, from first oil to decommissioning.
FAM is a universal production optimisation interface, consisting of a range of interchangeable modules which can be attached to the FAM Hub – “basically a subsea USB port,” Enpro managing director Ian Donald explained to InnovOil.
The hub itself is a dual-port structure which is supplied either with new hardware, or permanently retrofitted onto existing infrastructure, and located at the PLEM, PLET or at the flowline termination either at the tree or manifold. “Our technology provides an enhanced subsea architecture which enables you to address some of the 10-20% gap in recoverable oil we observed between the use of platform wells and subsea wells. The FAM allows you to intervene on the wells more flexibly and in a simpler way,” Donald added.
Because the FAM is located outside the subsea tree, it is independent of other hardware decisions, allowing project teams to fast-track procurement. Modules can be used independently, in series or in combination to support various production optimisation plans, including stimulation, sampling, multiphase metering, pumping, flow assurance operations and more. Working with standardised architecture, Enpro says, enables it to deliver faster, more cost-effective and more flexible subsea systems.
Recently, the equipment was used for the first time by an operator in the Gulf of Mexico, enabling the organisation to achieve first oil production in under 12 months – a record time for the client.
Working in parallel The challenge in this case was to tie back a new production well via a single spur into an existing subsea flowloop in the Mississippi Canyon, via a 3.2-km line. Donald recalled that conversations first began during a subsea tieback conference in San Antonio and that discussions progressed, with Enpro Subsea eventually invited to assist in the design of a solution which could make use of the operator’s existing deepwater infrastructure at the asset, and a surplus inventory of standardised subsea hardware.
For the project to remain competitive, the operator also set a deadline of 12 months, from concept to first oil. Enpro business development manager for the Gulf of Mexico Adam Hudson explained: “The traditional method for installing subsea hardware, up until the latest downturn, appeared to be that the more complex you could make your equipment [and] the longer the lead time, everybody believed the more successful and safer your project would be. The latest oil price reduction has provided challenges to the market to innovate and to reduce cost while making the systems more reliable, and as safe or safer. Enpro’s technology meets this innovation challenge and exceeds the requirements with added flexibility and functionality, while reducing costs.”
In a bid to reduce cost and drive efficiency, the operator’s project team had moved from a dual flowline design down to a single flowline, and had evaluated different technologies for using goosenecks in a flexible flowline. “The technology present at the time did not give them that flexible design,” he said. “Enpro technology allows for that flexibility; for a small additional cost you’re able to save much larger amounts from the overall project cost. And it allows for the acceleration of the project.”
For the operator, Enpro’s offering “ticked a lot of boxes.” It allowed electronic components and valves to be retrievable, and enabled a comparable engineering solution in a smaller form. This made for easier installation by a flexible flowline installation vessel.
Overall, Enpro provided several key pieces of equipment to the project, including flexible goosenecks with integrated FAM hubs and isolation valves onto two different OEM jumper connectors; metering FAM that included a multiphase flowmeter, standalone water cut meter and acoustic sand detector; a Flow Assurance FAM that included a hydraulically actuated fail close valve, pressure sensors, temperature sensors, chemical injection valves and an Intervention FAM.
The modular design also enabled the team do parallel engineering. A subsea tree could be installed and completed more than four months before the additional electronic components were in place. In this case the component was another piece of new technology, a standalone water cut meter, which allowed the operator to monitor the water cut in the produced fluids. The ability to deploy this via FAM enabled the operator to accelerate the entire project by three to six months. “In a traditional project the operator would have waited until April to install that component into a tree and then would have proceeded with the installation and completion of the tree, backing the project up and losing six to nine months,” Hudson added.
“By doing the project this way they didn’t wait on this technology. That sensor was installed into a retrievable FAM module with a much later delivery time requirement. The beautiful thing about the Enpro technology is that it’s jumper-based, and subsea well jumpers are typically the last component installed in subsea infrastructure and build out,” he explained. “That gives you more time to have long-lead electronic components delivered.”
Collaborative effort The use of the ESSI FAM system also helped address a number of unique challenges posed by the project location and specification. Because the design had eliminated a flowline and opted for a flow spur, heated dry oil could not be circulated if the well was shut in during emergency or maintenance. Instead, engineers opted for an isolation valve which could be remotely controlled from the facility, but were faced with the problem of where to mount it. Having evaluated using additional standalone structures to hold the valve, or mounting the valve into the gooseneck, they approached Enpro to help configure a module in which it could be included. Working collaboratively the two teams devised a system which met the requirements, and could also be deployed as part of a FAM module. “Doing so also gave them opportunity to inject chemicals into the module on both sides of the valve to further assist with safety and flow assurance activities,” Hudson noted.
Owing to the configuration of the field and the fact that production flowed downhill, there were also several contact points where gas and water could collect together at high pressures, risking hydrate formation. Hudson added that Enpro’s FAM solution allowed for one module to be retrieved and an intervention module installed in its place, enabling much simpler hydrate remediation, were that to occur.
Because Enpro’s technology is designed to interface with equipment from all manufacturers, including different hub connectors, the operator could use existing stock hardware, offering further cost savings.
The future of FAM Having successfully delivered the project within a challenging timeframe, and having provided additional functionality, Enpro is now pursuing work for longer tiebacks to the same installation.
Interest in the technology is also beginning to grow. “We’re seeing opportunities that would lead us to 8-well, up to 30-well developments, where this enables a very flexible strategy to be adopted,” Donald noted. In addition to new greenfield projects, the open architecture also makes ESSI and FAM cost-effective for retrofits. “One operator is fitting it to existing wells and is now planning to use the system for their new wells, as a useful life of field,” he continued.
The architecture can also offset risk. Donald drew attention to the fact that by offsetting some critical components from the tree, operators could work more flexibly: “If you put the same functionality in a tree it will cost you more, and if you damage anything on the tree you will have to come in with the ability to shut off the well and incur a bill of tens of millions.” Damaging a jumper, meanwhile, might be in the range of US$2-3 million – “There’s an order of magnitude difference in the downside costs as well,” he added. “In terms of risk and functionality we think the benefits are quite significant.”
With greater interest comes new innovation. The company has identified a range of production optimisation tools that can be deployed through this type of system and is now focusing its efforts on developing the broader architecture to support them. “We’re developing a 15ksi version of the ESSI which we expect will be available for deployment for next season,” Donald said. “We see certain applications for hydraulic intervention, metering, sampling and pumping coming very much to the fore.”
With no shortage of subsea wells on the horizon, the future of subsea engineering looks like it might get a little ESSI-er.