Spotting oil wells on land is easy, just look for the pump jacks. They are a common sight because about 90% of the oil wells on land are on some kind of artificial lift.
Don Underwood, director of subsea processing at FMC Technologies, cited that estimate to make the case that the same factors that make pumps standard equipment on land should increasingly apply to wellheads on the seabed. “If it is 90% onshore versus single digits under the ocean, there is growth potential,” he said.
Realizing that potential has long proved elusive, made more so by the deep funk now in the offshore oil business. But he and others selling pumps sound upbeat about calls from potential customers looking at ways to add oil output without the cost of drilling wells.
“The (oil) companies’ management is demanding gains to production … but they are not willing to go out and do enormous greenfield projects,” Underwood said.
“The subsea playing field changed a lot after the oil crisis,” said Sven Olson, a senior consultant for Leistritz Advanced Technologies, which sells pumps made by Leistritz, a German manufacturing company, for oil industry use. Rather than major new field investments, oil companies are looking to add barrels by taking better care of existing assets.
The two of them, who work for companies selling big, subsea pumps, use phrases like “enthused by the response we are getting,” “tipping point” for pump use, and Underwood went so far as to declare it a “golden age for subsea pumping.”
To put that in perspective, a major upswing in this sector would not require a lot of orders.
A 2016 survey of the market by Offshore magazine listed only 40 subsea boosting projects in the world, and 11 of those were classified as “abandoned/removed.” The number of working subsea systems that year rose to 17, with 12 projects at various stages of development, it said.
In comparison, there are about 5,000 subsea wells, according to a panel discussion at the 2016 Offshore Technology Conference.
The biggest cluster of new fields on the list is in the US Gulf of Mexico (GOM). Development in ultradeep water, such as Chevron’s Jack/St. Malo, have been equipped with pumps from the start. The goal is to sustain high production in water 7,000-ft deep from fields 25 miles apart to a floating production unit located in between.
“We are using subsea boosting pumps at Jack/St. Malo, and other recent Lower Tertiary fields like Julia and Cascade-Chinook, also use subsea boosting,” said Stephen Thurston, vice president, Deepwater Exploration and Projects, Chevron North America Exploration and Production Company, adding “Folks are seeing the utility and value.”
Those deepwater new field developments were approved before oil prices plunged and exploration and production (E&P) budgets shrank.
“The purse strings in today’s environment are pretty strapped. There is not a lot of money,” Olson said. Adding a pump to increase the flow is considered if a production platform is running below capacity and it is possible to add “more production without a tremendous cost.”
About 20–30% of the subsea fields evaluated by Rystad Energy could yield enough added production to justify an investment in subsea boosting, said Erik Reiso, a partner at the Norwegian energy consulting firm.
Companies are open to the idea of adding a pump because “when the oil price contracts, there is more emphasis on an investment that has a quick return,” he said.
Changing Fields
A short answer for why subsea boosting has never taken off is: it has not been needed.
“Most of the wells have pressure that is high enough where one does not need a pump, as the natural pressure will force it to topside,” said Neal Prescott, executive director of offshore technology for Fluor.
But he emphasizes there is a limit to that approach. As fields age the pressure goes down due to reservoir depletion, and the energy required to lift the fluid rises because in general more of it is water, which is heavier than oil.
The result is less oil output, and eventually the operator must decide whether to make a significant investment in the field, sell out or, eventually, shut it down.
When offshore E&P recovers, oil companies are likely to find offshore reserves where subsea boosting is going to be needed. Smaller pockets of oil, reservoirs in ultradeep water, or difficult formations like the Lower Tertiary, present challenges to profitable production where pumping and related subsea methods may be needed to deliver the production required to justify the investment.
The tools are subsea versions of ones long used on shore: pumps, compressors, and processing units separating oil, water, and gas. Statoil is working to move those functions to the seafloor to create what it calls the subsea factory. FMC has built the handful of oil/water separators installed by Statoil and Petrobras.
While all the components for the subsea factory have been tried with various degrees of success, costs remain a barrier. At this stage, pumps are the most proven option.
To convince E&P companies there can be a financial upside in making that investment, Rystad has been hired by companies selling pumps to provide economic analysis showing when adding a subsea boosting system makes sense. The firm estimates the likely return on investment based on the field specifications and how much the addition of boosting will affect the output.
The cost and difficulties associated with installing a pump in a working field on the seabed mean that more often than not, the investment is not rewarding at current oil prices. But in the cases where it is, the payback period can be in less than a year, Reiso said.
“There is a very wide range of (annual) returns, running from 10% to more than 80% a year,” with the largest number clustered around 20%, he said.
Winning fields offer a combination of sufficient oil and pressure in the ground. Putting a pump on the seabed able to handle both gas and liquids improves production by reducing the force required to overcome friction and gravity—the hydrostatic head—as it travels up from the seabed to the production platform. That can significantly improve production if the pressure in the ground can apply a significant push.
“You need to have sufficient pressure and (oil) volumes in the reservoir” to produce significantly more,” Reiso said. That means the rewards for adding a subsea pump at the tail end of a field’s life are likely limited.
“There are quite a few time-critical projects out there that need to have boosting in there sooner rather than later,” he said.
The motivation may include a political push from governments that want to extend the lives of oil fields that have been a critical part of their economy. For example, in Norway the government’s goal is to produce more than 60% of the oil in the ground from offshore fields where subsea completions are common.
“At the end of the day, regulators, especially those in the North Sea, do not want you to walk away from a producing asset,” Olson said. Subsea boosting can also be used to delay the day when production has dwindled to the point that the operator must pay the far higher cost of shutting down the field and removing all the structures.
Mental Images
One of the difficulties facing those selling subsea boosting is that it does not fit neatly into the thinking used by those who do artificial lift.
Their mental model of artificial lift does not feature hulking multiphase pumps on the seabed or electrical submersible pumps (ESPs) outside wells in subsea flowlines.
“Most artificial lift is done inside the wellbore,” said Rajan Chokshi, whose artificial lift consulting firm is called Accutant Solutions. He was a co-chair of the SPE Artificial Lift Systems for Optimised Production Workshop in July. “Subsea multiphase boosting on the seafloor near the wellhead could be considered a way of lifting the fluid. But if you go to artificial lift conferences, you would not find a single mention of it.”
For consultants like Chokshi or Jeffrey Dwiggins, managing director of Artificial Lift Solutions and another member of the workshop committee, there are limited opportunities to sell services to the few big players in a small sector.
“If you look at lifting as a whole, it is a very small slice of the pie,” Dwiggins said. He pointed out the first option for artificial lift in subsea wells would be gas lift, which uses gas injections to reduce the fluid density of the oil.
But when the wellhead is located a mile below the production platform, at some point the natural pressure in the ground can use a lift. Multiphase pumps are costlier and less familiar in the industry than ESPs, but their power is not limited by the dimensions of the well and they can handle high levels of gas that can damage an ESP and are easier to reach if repairs are needed.
The number of ESPs in subsea fields has been limited by the cost and difficulty of reaching them through a tree on the seabed. There is both the expense of hiring a drilling rig equipped with a riser to do the work, and the production lost waiting for the job to get done. “There are very, very few applications of ESPs downhole in subsea fields,” Reiso said.
But ESP interest remains. They have been used for lift outside of wells in installations designed to limit the factors that can shorten ESP pump life.
For example, Prescott said Fluor developed a system in 1985 for Highlander, a small North Sea field where the production flowed into a caisson that went down 1,000 ft below the seabed. That allowed the sand to settle to the bottom, and the fluid and gas to separate. The system extended the life of pumps needed to move the production 8 miles to Texaco’s Tartan A platform by protecting them from high temperatures, extreme pressures, sand, shocks, and having to handle high gas cuts, Prescott said.
Other fields, such as Shell’s Perdido field in the GOM and Total’s Pazflor field off Angola, have used gas/water separation. But it is a short list.
There are also projects to reduce the cost of installing and replacing ESPs in subsea wells that do not require a drilling rig and riser. Companies such as Zilift are working on a deployment method using a light well intervention vessel and cable deployment.
Norman Liley, commercial and intellectual property director for Zilift, based in Aberdeen, said customers are looking for a lower-cost method, and so far the company has successfully tested a method in an onshore well, and is working on adapting it to offshore deployment of high-rate pumps.
Nebb Engineering in Oslo, Norway, is working on building a subsea variable speed drive (VSD) that could be placed near the wellhead and adjust the pump speed to variations in the flow in the hole. “What we have learned is that there is a huge interest from the oil companies for subsea VSDs in the range 350–1,500 kW,” said Martin Siljan, chief engineer for Nebb. “The primary application/market for this unit will be artificial lift through ESPs.”
Technology Changes
Nebb initially created a VSD that was rated for 45 kW and is now looking to scale it up to a larger size, but that unit is tiny compared to the ones built to deliver megawatts of power built by Siemens and ABB.
Those suppliers, and companies in the subsea pump business such as FMC, are working on adapting bulky electrical equipment now found on production platforms so it can be installed on the seabed by a workboat.
Moving power systems from the crowded decks of production platforms to the seabed is “the holy grail” for competitors in the business, Underwood said, pointing out that for big pumps “the variable speed drive is the size of a house.”
Doing so would remove a barrier to installing a pump in an older field—getting permission to install bulky electrical equipment on crowded platform decks.
Longer term, the goal is to lower the cost of offshore development by reducing the need for platforms by making it economically possible to tie in more distant fields. This could allow a big company to connect many fields into a single platform, or many companies to send their production to a platform owned by a third party.
Customers have said they need to see major price reductions in subsea boosting. The cost of the pump is a beginning point for that calculation, but there are other variables such as the sort of vessel needed to install it, the cost of maintenance, the reliability of the system, and the hardware needed to power and control it, among other things.
Those considerations are being factored into pump designs. “We are making things smaller, reducing the part count, and when you reduce the size and weight you reduce costs in our world. When you reduce the part count you improve reliability,” Underwood said. “The reality is the cost of the pump is miniscule compared to the system needed to put it in place and the intervention needed to do it,” Underwood said.
Umbilical lines used for control and power are a big line item. Those working on subsea electrical control systems are trying to move functions closer to the wellhead to reduce the size and complexity of these lines with a goal of reducing the weight and expense of the hardware, the installation, and the number of things that could go wrong inside it.
Another key cost variable is the way subsea upgrade projects are engineered and managed. Variables range from finding creative ways to reuse existing equipment—such as an umbilical no longer required for another piece of equipment—to convincing a skeptical operator that a project to modify a subsea system can be done as planned with a minimum of lost production or damage to the system.
Convincing a field owner to do a major upgrade could be a “major effort” Chokshi said, because “people tend to shy away from changing anything as much as possible after lowering the initial package on the seafloor.”
For Further Reading
SPE 146784 Comparison of Multiphase Pumping Technologies for Subsea and Downhole Applications by Gong Hua, Gioia Falcone, Catalin Teodoriu, and Gerald Morrison, Texas A&M University.
