Après the moratorium of deepwater drilling in the Gulf of Mexico, operators are once again exploring for opportunities offshore. Yet, escalating costs for production facilities can prohibit the profitability of some marginal fields. Jeannie Stell explains why innovative subsea tieback technologies and strategies make all the difference.
The energy industry is entering a period of profound transformation as new technologies and innovations reshape the landscape. In fact, “the one constant in the industry will be innovation,” according to Daniel Yergin, vice chairman of IHS and author of The Quest: Energy, Security and the Remaking of the Modern World.
Supporting the innovation trend is some $223 billion expected to be spent on deepwater projects and technology during the next five years. According to a recent report by consulting firm Douglas-Westwood, the expected capex is a large increase over the firm’s previous estimate of $139 billion-spend for 2012 through 2016.
Yet, challenges lie ahead, especially for long-offset and deepwater wells. High-cost platforms and spars can havoc with tight economics as field architecture favors fewer count wells with extraordinary productivity spread out over larger sea floor areas. As a result, subsea tiebacks, and new innovations thereof, are becoming increasingly attractive. Even the surface-breathing hardware for gathering, initial processing and metering are giving way to sea floor mounted equipment, doing the same job, next to the field and with far less cost than that of the bottom founded or floating support structure. Many E&P companies are turning to subsea tiebacks to link multiple wells to a single facility/ hub, either their own or those owned by third-party operators, to enhance efficiency and economics.
In March 2012, Anadarko and its partners in the Caesar-Tonga play achieved first oil from their deepwater project in the Green Canyon of the Gulf of Mexico while using new technology—the lazy wave riser—to move some 50,000b/d of oil and 50mmcf/d of gas from three producing wells. The field’s reservoirs are Miocene age and subsalt.
Caesar-Tonga wells are drilled through as much as 15,000 feet of salt canopy before exiting into rock formations just above the reservoir. In fourth-quarter 2012, Anadarko finished drilling its fourth development well in the field, which it expects to complete and bring on line in second-quarter 2013. The company is using new lazy wave riser technology to great advantage in the play. The steel lazy wave riser, specifically designed for the Caesar-Tonga project, is not a true steel catenary riser, but rather a variation on the steel catenary riser theme with added buoyancy and flexibility.
Among the innovative components of the project, the riser flow lines utilize pipe-in-pipe technology in which a specialized insulation layer is placed in the space between the two pipes. This high-strength steel pipe-in-pipe technology acts as the fluid conduit with a number of buoyancy modules to create an arch in the riser. The arch improves the flow lines’ performance by keeping stresses in the pipe within allowable limits as the spar moves under the influence of external forces. To create the arch, 160 discrete buoyancy modules were installed on these risers. The risers must depart the spar at a slight angle and gradually curve across and up to form the arch. The riser shape then takes a downward bend until it touches the seafloor.
“Operating in 5,000 feet of water is a challenge that requires experience, confidence and a safetyfirst mindset,” says Mike Beattie, Anadarko’s general manager of Gulf of Mexico deepwater facilities. “That also contributes to the primary engineering challenge of successfully delivering the Caesar-Tonga project, as it required a deepwater riser system that would safely overcome the challenges of a complex deepwater environment and that could operate under the high producing pressures expected from the Caesar-Tonga reservoirs.”
The partnership was also challenged to significantly expand the capacity of its existing Constitution spar floating production facility with the addition of nearly 1,300 tons of processing equipment to the topsides of the facility. In response, the project team designed the two riser systems, the flexible riser and the steel lazy wave riser, concurrently.
The project design team also required that flow lines, risers, manifolds, trees and multi-phase flow meters accommodate an environmental pressure of nearly 13,000 psi. After qualification testing, the partnership selected the steel lazy wave riser design, making this the first application of such technology in the Gulf of Mexico and only the second application of this technology in the world.
“The Caesar-Tonga mega project provides an illustration of the value of Anadarko’s hub-and-spoke philosophy, as it was able to avoid almost $1 billion of capital investments that would have been associated with the construction and installation of a new host production facility,” says Beattie. “Anadarko’s hub-and-spoke approach to develop area-specific oil and natural gas fields involves making an initial investment in a host facility and producing those discovered reserves as the base project.”
“LLOG uses tiebacks because many of its prospects would not support their own floating production systems.”
Anadarko’s 100%-owned Constitution spar, the hub in this development, began producing in 2006 from the Constitution and Ticonderoga deepwater fields. Future discoveries will also tie back to the existing infrastructure, saving significant time and capital. By leveraging the Constitution spar, the company also increased the facility’s production capabilities from a declining asset with 10,000b/d of production to up to 60,000b/d from the three existing subsea wells in the Caesar-Tonga field and the nearly completed fourth. Also, the tieback option enabled production from the field to come online two years earlier that would have been possible with a newly constructed facility.
Elsewhere, LLOG, one of the top ten privately owned E&Ps in the US, has been involved in 17 subsea tieback projects during its history, and seeks new, proven technology to continue its success. Currently, its Who Dat development in Mississippi Canyon 503/504/547 is tied back to its own floating production system, which is the only privately owned floating production system in the world. There, LLOG is ramping production up to 20,000b/d of oil and about 22MMcf/d of gas from its three existing wells. Nine more wells are planned. The floating production system can handle about 60,000b/d and 150MMcf/d.
LLOG’s Mandy project in Mississippi Canyon 199 and Goose project in Mississippi Canyon 751 also utilize the technology and are tied back to Total’s Matterhorn platform. The three-well Mandy field is tied back to Matterhorn, and Goose is a single well that is remotely tied into another one of LLOG’s existing subsea systems at MC707, which ultimately flows into the Williams-owned Grand Isle 115 platform.
“We also participate in Green Canyon 448, also known as Condor, and Green Canyon 141, which also use subsea tiebacks,” says Rick Fowler, vice president of deepwater projects for LLOG.
In the past, LLOG used subsea tiebacks because many of its prospects would not support their own floating production systems, he says. Today, other metrics continue to make subsea tieback technology a good choice for the company.
LLOG chose subsea tieback technology rather than using dry trees for its Who Dat field for several reasons. “First, we didn’t feel that the intervention savings were going to be worth it to build a dry-tree solution,” he says. “Second, we bought the Who Dat floating production system on spec, so it was already built and we were able to get it on production a year earlier than with any other options we were considering. And third, for Delta House, a new development which we operate for ArcLight Capital Partners and is under construction right now, we also chose to go with a wet-tree solution because we plan to centrally locate that floating production system between three other fields that will be tied back.”
Typically, LLOG uses Super Duplex or 19D Duplex stainless steel umbilicals in its systems, and most of its umbilicals are static. “We do have a couple of dynamic umbilicals that typically involve a number of tubes and some quads. In general, our preference is to use proven technology wherever possible.”
LLOG has an alliance with FMC Technologies to provide LLOG’s control systems for all of its subsea projects. Many operators bid out among multiple providers of control systems, but LLOG sees an advantage with sticking with FMC. “We consider that an advantage because we can learn one system and we have one set of contacts with our suppliers. If there is a problem, we are very familiar with the system because we use it everywhere,” said Fowler.
The company also spends significant time on flow assurance, which is one of the big challenges with long subsea tiebacks, he says. LLOG’s Grand Canyon 448 field is connected with a 34-mile umbilical—the second longest oil subsea tieback in the world.
“When it comes to flow assurance, we have to worry about wax, asphaltenes and hydrates,” says Fowler. “With Grand Canyon 448, we are blessed with good fluid with very small wax content. Otherwise it would be extremely difficult, if not impossible, to maintain flow and temperature above cloud point at ambient sea temperature.”
As a further preventative measure against blockages, the company uses methanol and low-dosage hydrate inhibitors to prevent hydrates, where necessary. In the rare case of wax deposits, LLOG has used chemical solutions to reduce the cloud point or minimize wax deposits in the lines. “Thankfully, we’ve never really had to deal with any significant asphaltene problems,” he says.
To detect blockages, LLOG monitors its operations in real time and pays close attention to pressures by using subsea gauges at the wellhead and platform, among other procedures. “We typically install a piggable loop where possible to facilitate the remediation of either a hydrate or a wax plug. If it’s a hydrate, we can blow that out from both sides. For wax, we can use the loop to circulate hot oil.”
Typically, LLOG integrates expandability into its system. For example, if a subsea manifold is required, the company will install a four-slot manifold, although only two wells are imminently planned. “That’s also useful for operations,” Fowler says. “Every once in a while, we might get one tube of the umbilicals that won’t work. Designing the system to be expandable gives us redundancy.”
At Who Dat, the company installed four flexible risers with a two-loop system. During the project, one of the flexible risers was not available. By building in the loop system, LLOG was able to begin production as scheduled without waiting to solve the riser problem.
Going forward, Fowler sees possible constraints of third-party host production facility capacities. Many deepwater oil producers pay production facility owners a processing and handling fee, about $3 to $5 per barrel, to process, store and offload their production.
“We’ve seen a lot of upward pressure on PHA fees,” says Fowler. “Recently, negotiations for firm capacity have been challenging. Due to the current favorable oil prices, the companies that own host facilities might want to keep that capacity for their own wells, even if there is only a marginal chance they might need it. It’s better to get $100 per barrel for your own oil than to get $4 per barrel for processing someone else’s. That can create a difficult situation for tieback producers.”
Conversely, some host facilities are being designed larger than necessary for the current slate of wells, he says. The overbuilds are likely due to host facility owners looking to gain third-party PHA fees without giving up capacity needed for their own production. “We are also seeing more host facilities owned by midstream companies, as opposed to operators, for those reasons as well,” he says.
Rick Rainey, spokesperson for Enterprise Products Partners LP, agrees. The company’s Gulf of Mexico Independence Hub platform serves producers with a processing capacity of 800MMcf/d and its gas-volume capacity on its Independence Trail pipeline is about 1Bcf/d. “This allows the development of these fields because we provide the infrastructure that is already in place to connect to other systems that provide access to the markets,” he says.
Pumping and compression
To support LLOG and its other clients in their subsea-development efforts, FMC Technologies continues to invest in research and development projects for deepwater and harsh environments. “The focus of many of FMC’s current projects is to revitalize old fields or help new fields achieve better flow and production rates and manage longer offsets,” says FMC Technologies’ emerging technologies director, Brian Skeels.
Umbilical distribution manifold at LLOG’s Who Dat development is tied back to its own floating production system, the only privately owned floating production system in the world.
“We continue to incrementally add more to our kit for subsea processing and pressure boosting. We are working to stair-step our pumping technology with liquids and multi-phase flow so we can learn how to do gas decompression better for the future. Gas is a harder nut to crack than liquids,” he says.
To enhance subsea liquids production, the company has been collaborating with Sulzer Pumps Ltd. to fully qualify a new multiphase 3.2-MW, 5,000-psi helico-axial pump system for subsea high-boost applications. The technology marries Sulzer Pumps’ pump hydraulics with FMC’s high-speed permanent-magnetic motor technology. The new equipment includes helico-axial multiphase pumps, hybrid pumps and single-phase centrifugal pumps.
Along with new boosting and compression capabilities, FMC is looking to bring more efficient and smaller footprint power and processing to subsea operations, says Skeels. “One difference between pumping liquids and gas is significant increase in power requirements. If it takes 1 MW of power to operate a liquid pump, it takes 10 MW to operate a gas compressor.”
Another challenge is to reduce communication lag time between the subsea control and sensor equipment and operators, which could be several minutes. “Given some extremely long offsets, like going under the ice in places such as offshore Norway and Russia, operators will need to rely more on autonomous and feedback controls at the subsea field to instantly react to changing process conditions, augmenting the command-and control station far away on a spar or platform. The lag time associated with the remote distance, sometimes as much as 200 km away, could influence the amount of time the operator has to diagnose and react to a problem or changing situation.”
To reduce lag time and losses associated with electric and fluid transmission over long offsets and ultra deepwater, FMC Technology is working on new-generation subsea power and control systems.
“We are working toward what Tyler Schilling coined as the ‘silicon seafloor,’ where resident ROVs service electric-actuated processing valves and localized hydraulic power units at the subsea factory.”
Electric power lines will power and control subsea processing and pumping directly while subsea controls, either electric or electrohydraulic, will branch off to operate subsea trees and manifolds, he says. “We are still in the early stages, but we see exciting days ahead through the use of ROV robotics, to be a force multiplier of technologies to give our customers a wide range of flexible platforms to work from.”
Another challenge is the need for new monitoring technology, says Skeels. “In deepwater current and extreme weather places, like the North Sea, where the ocean acts like a washing machine, drilling, workover and production risers are subjected to an increasing number of bending cycles and adverse loads over longer durations. These loads often find their way into foundations of subsea wells while attached to a drilling rig, spar or floating facility.”
Traditionally, wells were drilled and accessed for only a couple of months, then left structurally static on the sea floor while the well was producing. Now, operators are focused on the wells for far longer periods, drilling deeper and performing much more complicated horizontal drilling and completion maneuvers. All of this time under cyclic loads will eventually fatigue and wear out even the most robust equipment. Risers, wellheads, connectors and casing all have a finite fatigue life, but it depends on the cyclic frequency and amplitude.
“This is where monitoring comes in. Risers soon will need robust, long-term instrumentation to give manufacturers, contractors and operators a real-time scorecard on the cyclic abuse Mother Nature has dished out, and how much remaining life is in their equipment as a result,” says Skeels. “This will give everyone a better understanding of when and where to repair and replace hardware and, more importantly, avoid unforeseen calamities.”
Riser configurations are also evolving. All flexible pipe, top-tensioned steel, flexible risers, and steel-catenary risers are used to tie back to increasing numbers of floating facilities in ever deeper and remote locations. Although the application drives the decision of which type of riser to be used, operators and fabricators are looking to more novel concepts as fields move into deepwater with field pressures as high as 10,000 to 15,000 psi. The cycle count from harsher environments and higher internal working pressures are demanding thickwalled risers, which can be very heavy. “Just trying to hold them up with a floating surface vessel is approaching technical limits.”
As such, the equipment industry is working to develop new riser materials such as carbon-fiber composites to reduce riser weight. “These new materials seem to have incredible weigh-savings, but we know little about how they react with wellbore fluids or chemical treatment cocktails, nor how they behave mechancially over a long period of time. And we have little indication of what the tell-tale signs are when their end-of-life is near,” says Skeels.
The industry needs to gear up on monitoring technology during the next few years, to quantify the effects that motion and internal wellbore production has on riser performance in general, and new materials in particular. As the number of HP-HT fields increase, the effects of temperature and pressure spikes will need to be added to the data collected from the fatigue by water motion and vessel movement.
“Drilling and production risers, pipelines and multiphase equipment, and anything that can expand and contract as equipment is turned on and off will have to be monitored for maintenance management. In fact, regulatory entities will probably demand it as time progresses. Materials-monitoring will be one of the new industries in the future.”
While deepwater production operations are exposed to high temperature and pressures, the trees, manifolds, jumpers and other subsea hardware also experience rapid cool-down during shut-in or initial start-up procedures, so the application of very robust insulation is necessary to prevent the formation of hydrates and wax blockage in flowlines. “We have been working hard to push the envelope on that,” Skeel says.
To help protect risers and subsea tiebacks, FMC Technologies continues its research on high-temperature versions of wet insulation. “We’ve been showing our Novalastic HT product, a glass-bead-impregnated foam, at the Offshore Technology Conference and other shows. Current applications can work with wellbore temperatures up to 300 °F. And we are looking at pushing performance to work in long-term applications at even higher temperatures,” he says.
Anadarko’s 100%-owned Constitution spar is the hub for the Caesar-Tonga field development.
Also, FMC Technologies continues its efforts to increase its modular approach to subsea equipment field architecture. “I think of these as building blocks,” says Skeels. “We try to make these systems in small blocks so that operators can build whatever they need and deploy those from smaller vessels. Modular design started catching hold in the late 1990s, but now it seems to be more important than ever. So we keep pushing to improve that.”
Going forward, the industry is going to continue to push the limits of technology, forecasts Skeels. “The industry is almost reinventing itself for HP-HT technology. All of the subsea equipment is interrelated, so improvement in efficiencies and controls in every aspect will become increasingly important.”
Parker Energy Products, a division of Parker Hannifan Corp., also supplies tieback technology to LLOG and other deepwater developers, with tieback lengths ranging from 300 ft to more than 25 mi.installed in the Deep Gulf Condor development. The company supplies 316L tubing for shallow water applications, Nitronic 19D zinc-coated tubing, seam-welded super-duplex tubing for steel-tube flying leads and control umbilicals. Parker has worked with LLOG since the company’s first subsea project and continues to supply its Mississippi Canyon development.
“We run the traps to determine the specific characteristics of the field and life requirements, then make a case for the best material, best delivery, and cost-benefit ratio,” explains Craig Anderson, general manager for Parker. “There is a very limited supply of seamless, coiled super-duplex tubing in the world, and again, based on the parameters of the field, that material can be overkill. The seam-welded materials, which are more readily available, are slowly being accepted by the operators as they get more use in the water. Proper welding techniques and better inspection processes show that this can compete against the seamless material.” OE