While Norway is down (courtesy of a two-year oil and gas slump) it certainly is not out. The Norwegian maritime and subsea pedigree extends centuries, and despite a momentary bump in the aquatic road, William Stoichevski uncovers some Rising Subsea Stars.
The merging in May of installation and equipment giants Technip and FMC into TechnipFMC eclipsed some news, so you might have missed the brilliance of wellhead, tubular and downhole stars shining from the depths. Beyond the success of TechnipFMC business, Forsys, there’s the entrepreneurial activity of brilliant new and established older players as well as some locally based engineering dynamos and their company-sized ideas.
The largest ever subsea asset deal featured the parent companies of engineering outfit Forsys, an outfit fresh from winning the job of designing subsea operator Statoil’s Trestakk development offshore Norway. The subsea tieback to the Aasgard A floating production storage and offloading vessel includes all systems and related services from the FPSO’s hanging risers to the wellhead, including umbilical, riser, flowlines and the installation and readiness of the subsea production system. The ability to do combine service and equipment with less seabed sprawl is touted as a key cost-cutting effect deriving from the combination of Forsys’s 50-50 parent entities. Using “next-generation” subsea architecture, Forsys Subsea’s business model is to cut the total imprint of subsea umbilical, riser and flowline systems (SURF) and subsea production systems (SPS). The same is now being said of TechnipFMC, an alliance said to address the disparity between $29 oil and well costs that had overrun the $100 million mark. At Forsys’s creation, Subsea production systems, risers and flowlines and installation had become 35 percent of an offshore development. Topsides to control production and drilling and well completions had reached 60 percent of that number, Forsys leadership says. The company says getting in early with its front-end engineering; staying the course with its condition and performance monitoring (CPM) and joint R&D are core to its cost-cutting offering.
Houston small business award winner Fishbones has found a missing-link niche in stimulating wells to produce as much as possible — quickly. Fresh from OTC Spotlinght honors for the drilling solution Dreamliner MST, the company’s new Fishbones MST solution is “something customers have been waiting for,” says Fishbones’ CEO Eirik Renli, a former Baker Hughes country manger. “When you ship it to the rig, it almost looks like a regular liner,” he says about the company’s Dreamliner multilateral drilling stimulation technology, or MST. The tech uses diffuse pressure and acid to extend a series of nozzle-ended pipes (like the ribs of fish bones) from the casing along a length understood to be a max of about 10 m. Tiny discs prevent early deployment of the 18 millimeter rods which “wash” themselves into the reservoir using 3,000 dpi of pressure.
A Society of Petroleum Engineers paper at the end of May 2016 reported on Statoil’s first-ever pilot trial of the MST at the Smoerbukk South multilateral production well, where production was made possible in tight sandstone by the Fishbones completion, a feat “previously regarded as not feasible” due to variable reservoir quality that ranged from “bricks to tiles”, according to Statoil, a nod to this new ability to tap low porosity stone’s for hydrocarbons. A drive shaft spins fluid and then tiny turbines at the end of the “ribs” to create sideways stim. The completion method simultaneously makes large numbers of laterals out of one wellbore. Not yet an option for shale, the system is ideal for tight sandstone or carbonate akin to that found in the North Sea and the Middle East.
“We can cover the whole 360 degrees around the reservoir … It’s only limited by the hydraulics calculations,” Renli says. At the end of the Fishbones tool, an anchor holds things in place to prevent the system’s sideways movement. The anchor is a shoe fitted with a disc that “bursts open” at the right pressure with normal drill fluid.
“In two to three hours, you’ve stimulated a well,” he says. Time isn’t just a factor for the operators. Fishbones is getting by on trials, loans and a grant and needs some real business soon to keep the offer available to an industry in need of stim alternatives.
Subsea Design SeAlign
While all good things, it might be argued, contribute to IOR, calculations that identify time lost on “simple” but costly things — like connecting pipelines not about to meet in perfect alignment — are not always prized.
Subsea Design from unsung scrap-metals town Drammen is acutely aware of the industries struggles with aligning connections not in alignment, so they’ve come up with their trademark SeAlign: a tool that precludes the need to position massive “pipe-bending” structures or pricy connection equipment.
Subsea Design’s patent for solving misalignment is called a “self-aligning” connector and cuts stress on tubulars and space on the pipe spool, since less pipe is needed as slack. SeAlign is installed at the platform or template and at the end of infield pipe by an ROV using a trademarked connection system. The ensuing savings are said to have contributed to the massive cost reduction operator Statoil is reporting at its giant Sverdrup field development, for which 72 SeAlign connectors have been ordered in 8”, 12”, 14” and 16” sizes.
Subsea Design WLR
For that other overarching priority in today’s industry, heightened safety, Subsea Design has also engineered a wellhead load-relief system, or WLR, to carry the weight of whatever is brought to bear on a well, but especially risers, blowout preventers (BOPs) or containment equipment. Already tested by stately Statoil between 2014 and 2016, the WLR was found to cut “inert and dynamic bending and loading” by up to 90 percent. This “shock-absorber” for taking on wellhead weight also extends the operating weather window for drilling by granting a bit more rig drift. Images show the WLR installed on a BOP and looking flexed to buttress its load. Four to eight lines of clamps wires and advanced tensioners secure the BOP in place atop the wellhead or x-mas tree. Trial analysis included seabed compression and casing studies, and (judging by the PowerPoint) fatigue life or “allowable days of drilling (completions or re-entry)” increased (with the WLR) by from 50 to 5,000 days!
It was at Subsea Valley in April 2016, that a DNV GL wells expert revealed that new, “alternate” plug and abandonment strictures were on the way. The new recommended practice is based on a risk-based abandonment assessment.
Norway is part of a $5 billion well P&A market, a source told MTR, and this high cost of decommissioning was the driver of the new RP. The Norwegian market is “35% of that estimate.” Much of the cost is related to getting a jack-up rig above subsea wells with supplies of cement. The other windfall is the time saved leaving an exploration well.
“Do all wells need the same requirement,” the Class man asks somewhat rhetorically. DNV GL is hoping to foster site-specific regulation for P&A that would even the playing field, as Norwegian P&A rules require filling a 100-meter top-hole plug, although 8 m is enough in other oil provinces. The RP includes marine wells based on ISO 31000 standards. The recommendation follows a P&A project at the Huldra field, where Statoil learned that one double barrier was as good as five single barriers and would earn a savings of 100 million kroner on the test wells involved. Some 3,000 wells on the Norwegian continental shelf need P&A work, so many are quietly excited about the RP. Although he didn’t specify, the DNV GL man said new technology — not just cement pours — would also help bring the cost of P&A down
Wind-Powered Oil Recovery
As classification societies go, DNV-GL is perpetually on the cutting edge either along or via Joint Industry Projects (JIP) to push the envelope and deliver seemingly futuristic technical solutions to some of the world’s more vexing maritime and subsea problems. Courtesy of a DNV-GL-led WIN WIN JIP, the organization has delivered again, announcing an innovative solution designed to both help the environment as well as the profitability of the beleaguered oil and gas industry: Wind-Powered Oil Recovery. Specifically the plan is designed to use floating wind turbines to power a water injection system. JIP partners include ExxonMobil, ENI Norge, Nexen Petroleum UK Ltd., Statoil, VNG Norge, PG Flow Solutions and ORE Catapult. “We can now see renewable energy as a large scale source of power to offshore oil & gas operations. By using the recent developments of floating offshore wind turbines this concept can offer a clean, reliable, and cost effective alternative for powering water injection in offshore locations,” said Remi Eriksen, Group President and CEO of DNV GL.
The costs for wind powered water injection have been compared with a conventional alternative where water is injected via a flow line from the host platform. While the WIN WIN technology has higher operational expenditures (OPEX) compared to a conventional alternative, the significantly lower capital expenditure (CAPEX) means that it compares favorably over the long term. WIN WIN is therefore a commercially competitive alternative in a range of cases, particularly when host platform capacity is limited or injection wells are located far away. The savings will vary widely based on the project and the installation, but the JIP has estimated possible cost savings of approximately 20%.