Subsea innovations: Building reliability into complex, high-risk world

New subsea tree designs, simpler connection systems and remote technologies among advances helping to enhance recovery, field life

By Katie Mazerov, contributing editor

In the high-risk subsea world, innovation has historically been driven by safety, reliability, economics and efficiency. Now operators have added a new watchword to their wish lists for this critical arena: collaboration. As subsea developments become increasingly complex, service companies and subsea vendors are recognizing they must work together more than ever to ensure tools and equipment are properly designed, developed and tested, and that they function as expected and minimize risk.

Growing activity in the Arctic, Brazil, West Africa and the Gulf of Mexico (GOM) are pushing the limits of today’s technologies but also providing opportunities for advancing subsea completions and production equipment. A heightened focus on equipment testing and qualification, new subsea tree designs, simpler connection systems for running tools, expanded use of remote technologies and research on the effects of high temperatures and pressures on materials and metals are among industrywide efforts under way.

OneSubsea, a company formed last year by Schlumberger and Cameron International, offers what the company sees as a step-change in reservoir recovery through integration and optimization of the entire production system over the life of the field.

“The integration of the production system will be accomplished by combining superior reservoir knowledge and wellbore technologies with industry-leading subsea technologies, all together delivering enhanced productivity, reliability and integrity,” said Justin Rounce, vice president, marketing & technology for OneSubsea.

As technology increases in complexity, the risks correspondingly increase, requiring more rigorous qualification and testing, Mr Rounce noted. “The measurement and documentation of risk associated with new technologies is captured through several tools. For example, financial scenario planning is compiled at the start of a new technology development project, along with simulations based on the Monte Carlo processes, which are utilized to understand complex relationships between technologies and investments.

In addition, as the industry continues to grow, we adopt and report our technologies and their associated readiness levels through easily understood ‘brackets,’ such as American Petroleum Institute (API) or Det Norske Veritas Technology Readiness Levels.”

Within the subsea sector, primary technology developments have focused on two areas, Mr Rounce continued. “First is the continued development of new hardware to improve offshore efficiencies. The first development of note is around connection systems, completing and generating a full line of clamp connection systems to eliminate the need for running tools.”

The company also has received orders for the recently introduced OneSubsea Vertical Monobore Tree System, which incorporates high-capacity drilling connectors and increased hydraulic and electrical downhole line functionality. The system uses a technology that protects and isolates the control line systems during production, injection and workover operations.

A second key technology focus, highlighted further by the creation of OneSubsea, is around enhanced recovery of hydrocarbons. “We have developed processing and boosting systems to meet the increasing market requirements to facilitate and enhance oil recovery,” Mr Rounce said. “Additionally, the reservoir knowledge from OneSubsea benefits the design of subsea production systems by providing an integrated pore-to-process approach that will allow us to develop new and groundbreaking technologies to optimize production and potentially improve the recovery from subsea reservoirs.”

Alongside collaboration, operators also are seeking solutions that provide built-in reliability, especially in regions with difficult access to subsea fields and where the harshness of the operating environment impacts tool integrity.

Built-in reliability

“Anytime we put equipment under water and can’t access it for long periods of time, we have to build in reliability,” said Brad Beitler, vice president, technology for FMC Technologies. The company envisions deploying a complete, remotely operated facility on the seabed by the end of the decade. “Subsea completions make up 8% to 10% of the total field development cost, so equipment that is incorrectly designed increases the cost of the entire operation. The foundation is safety, and we make sure we have tight processes and procedures to ensure quality. For many products, we test to destruction to understand what the operating limits are.”

Industry’s push into harsher environments is driving much of FMC’s R&D at its three global technology centers, where R&D engineers, including some hired from NASA, actively manage 20 to 35 projects. Some of these involve high-pressure, high-temperature (HPHT) and Arctic conditions. “In the Arctic, the problem isn’t so much the cold but access to the wells, which may only be available two to six months a year,” Mr Beitler explained. For example, for one installation in Canada’s Jeanne d’Arc basin near the Arctic Circle, a barge had to be deployed to dredge a trench to protect subsea equipment from icebergs that often scour the seabed.

In 2012, FMC installed the first Russian Arctic subsea completion in the Kirinskoye gas and condensate field for Gazprom near Sakhalin Island, deploying six 5 ^1/8-in. by 2 ^1/16-in. enhanced horizontal trees (EHXT). The design eliminates the pressure-containing internal tree cap and relocates the pressure barriers to the tubing hanger to facilitate installation of the

remotely operated vehicle (ROV) tree cap outside the critical path, reducing rig and installation time.

In terms of HPHT conditions, “We are going far beyond API specifications for 15,000 psi and 350°F. We are taking extraordinary efforts in examining the metallurgies, materials and equipment testing qualifications so we’re absolutely sure systems are going to do what we want them to do,” Mr Beitler said.  “For subsea trees, there is a lot more inside the tree in terms of its structural integrity and engineering, such as bending forces imparted on the tree by the riser, that must be taken into consideration.” To counter high levels of carbon dioxide produced along with oil in the pre-salt developments in Brazil and West Africa, FMC lines subsea trees and piping to the rig with corrosion-resistant alloys and specialized coatings.

FMC and Sulzer Pumps have developed a 3-megawatt subsea multiphase pump that “boosts” oil and gas from the well to a floating or land facility, increasing recovery in

reservoirs as they decline in pressure. The technology can be deployed to revitalize old fields, help new fields achieve better flow and production, or enable longer offsets.

FMC’s enhanced vertical deepwater tree (EVDT) allows for the installation of a new-generation blowout preventer (BOP) on top of the tree on high-pressure wells in up to 9,843 ft (3,000 meters) of water. This provides more options for entering the well, either through the BOP, a completion riser system run by a rig or a light well intervention system from a monohull vessel.

Looking ahead, Mr Beitler believes that autonomous control and monitoring, subsea processing and electric technology will be required for the unique and complex challenges of the Arctic. “Technology is key for developing the Arctic in a sustainable manner.”

Flexibility in Brazil

One of the most challenging subsea regions is Brazil’s massive pre-salt basins, where water depths average 2,500 meters (8,200 ft) and pre-salt layers average 2,000 meters (6,500 ft) in thickness. To address the harsh conditions of the Santos Basin, GE Wellstream, a subsidiary of GE Oil and Gas, is developing flexible production pipes where each layer of pipe is made with a specific material. “With offshore activity in Brazil going deeper and deeper, the new frontier of technology is focusing on lighter and more flexible materials that are resistant to corrosion in terms of either temperature or chemical content,” said Marcelo Soares, global president and CEO of GE Wellstream.

“Operators want equipment that is more cost-effective, safer, easier to handle, lighter and less corrosive for the harsh environment,” he said. “Weight is a significant issue on these bigger developments because the whole supply chain, from manufacturing to installation to maintenance, is impacted.”

The company is on track to introduce the new flexible pipe technology within three years, including development, testing and certification, Mr Soares said. The pipes are being engineered to withstand the acidic environment of the Santos Basin and are expected to enhance delivery services of floating production, storage and offloading (FPSO) units that are so critical to production in offshore Brazil.

“For specific applications, operators can use conventional technology to go into these regions, but the costs are very high,” Mr Soares said. “This new technology will be more productive and cost-effective for operators. Because the materials are lighter, they deliver additional benefits in terms of safety, which is a baseline for everything we do.” After the technology is introduced in Brazil, the next target market will be West Africa, which is expected to have many operational similarities, he noted.

GE is building a $250 million Global Research Center in Rio de Janeiro, the company’s fifth in the world. GE Oil & Gas will create a subsea lab at this center to develop future technologies for pre-salt and ultra-deepwater exploration. The company also recently expanded its equipment production facilities in Niterói and Macaé in the state of Rio de Janeiro and in Jandira in São Paulo.

Interventionless designs

Another key consideration in technology development is design simplicity that promotes interventionless completions with a high degree of functionality. “Risk management is foremost on everyone’s agenda now, and our customers are asking for interventionless completion designs that have reliability built in,” said Nick Boyle, quality operations support manager, completions, for Schlumberger. “The idea of having a completion that is run only once is where the industry wants to be. In wells where production is declining, for example, remote monitoring control allows us to manipulate the components within the completion without the costs and risk of doing an intervention.”

Intelligent completions and reservoir modeling, used in the marketplace for many years, are receiving more interest from operators because of the expanded capability of tools that boost production. “Our expanding capabilities enable customers to be more flexible in their production profiles in those more challenging and difficult environments that do not have the same in-situ pressures seen in reservoirs 20 or 30 years ago.”

Schlumberger has developed an inductive coupling technology that facilitates the running of more instrumentation in a simplified way to achieve sand face monitoring and zonal control. The device minimizes the number of connections required through all the systems that interact, such as the subsea tubing hanger, the tree and control module. “The fewer connections and wellhead intrusions we have, the more likely we are going to have a reliable system,” Mr Boyle noted.

Customers also are expressing more interest in sand control solutions. “These are highly complex completion designs that significantly improve the productivity of the wellbore by holding back solids to allow the oil to flow through,” he explained. “We are doing longer and longer sections of sand control systems, which in the subsea environment are definitely challenging.”

Subsea R&D projects target pressure build-up, mudline kick detection, ‘super-shearing’

As industry continues its march into harsh, ultra-deepwater and highly pressurized reservoirs, R&D efforts have ramped up accordingly. Front and center is Research Partnership to Secure Energy for America (RPSEA), a nonprofit group engaging projects to ensure technology integrity for subsea development.

“Deepwater and subsea go hand in hand,” said James Pappas, vice president of RPSEA’s Ultra-Deepwater Program. “It is difficult to retrieve data. Even when we do, the tools we use often have a very short shelf life because of the harsh conditions. We have to create solutions that will improve reliability. For example, we don’t have reliable data on extreme high pressure, high temperature (HPHT over 350°F and 20,000 psi) corrosion curves.”

RPSEA, through a program funded by the US Department of Energy and managed by the National Energy Technology Laboratory, is providing financial incentives for subsea drilling and completions research projects. These cover annular pressure buildup (APB) mitigation, deepwater cementing, a super-shearing device, a mudline kick detector, smart drilling fluids and smart casing. RPSEA also is part of a consortium, along with several Texas universities, that has received $5 million from the new Ocean Energy Safety Institute (OESI) to develop a program to help guide the industry into frontiers.

RPSEA also is working to establish industry guidelines for mitigating APB, which occurs between casing strings as a result of temperature differentials and lack of an escape mechanism for subsea wells on the backside. “This has been a problem for industry and will become more of a problem in HPHT wells because of equipment limits,” Mr Pappas explained. “There are several mechanisms being used by operators, but we need to take a global look at them to determine the risks associated with these various potential solutions and their reliability.”

The same is true of cement contamination and sealing mechanisms to address problems that occur in conjunction with oil-based and synthetic-based muds commonly used in deepwater wells. “We’re going to create a best practices document on how to cement when using these fluids in the hole,” Mr Pappas said. “We will canvass the industry to determine what works and what doesn’t, then come up with a best practice to share with industry and the API Cementing Committee.”

A third project involves the development of a backup super-shear device to shear through heavy or thick equipment in an emergency. Installed as a separate piece of equipment below the subsea BOP, the device would be part of the drill string. “BOP manufacturers are working to develop a failsafe system, which may make this moot,” he said. “On the other hand, operators are indicating they want this backup system to increase reliability to avoid incidents.”

An acoustic device to detect mudline kicks and differentiate kicks from other phenomena in drilling and completions is also on the table. “Normally, the information we get about pressure, temperature and flow rates comes from electronics close to the drill bit, which then has to be interpolated with data on the vessel. This would provide a third and more accurate data point, right at the mudline, to determine if a kick is indeed occurring so appropriate action can be taken.”

An ongoing project involves a lab study of micro-electronics that could be pumped downhole with drilling or completions fluids to provide full-time monitoring while drilling or completing, or could be embedded in cement materials for real-time monitoring. Work also is continuing to determine if equivalent circulating density can be reduced or eliminated by reverse cementing.

Established last year by the US Bureau of Safety and Environmental Enforcement (BSEE ), the independent OESI will promote safe and environmentally responsible offshore operations. The team will use the $5 million over the next five years to develop a three-pronged program to:

• Evaluate and determine the best available and safest technologies for offshore developments;

• Identify gaps not being addressed and bridge those gaps with additional funding for R&D and technology;

• Develop a program for training federal inspectors and potentially field operators at a later date.

“Our goal is to devise a business plan, share it with BSEE and then find the resources to develop a viable program by utilizing academic and industry expertise in conjunction with federal regulators to improve safety through technological advances,” Mr Pappas said. “I see this as an extension of the efforts we’ve been doing, all of them ultimately aimed at risk reduction.”

In response to operators’ push into more challenging fields, Schlumberger developed the FORTRESS premium isolation valve, which isolates reservoir fluids in the lower completion when required. This enables operators to transition from the upper to the lower completion without the need for intervention. “This is a high-reliability valve specifically designed for deepwater and harsh environments that is highly tolerant to debris, which historically has been a challenge with valves like this,” Mr Boyle explained. “With improved reliability and enhanced actuation methods, the design provides predictable and consistent operation.”

The Pinnacle tubing-retrievable, surface-controlled subsurface safety valve, designed to operate in pressures up to 20,000 psi and highly corrosive environments up to 400°F, was designed for the GOM, where completions activity is expected to ramp up to record levels, Mr Boyle said. “The design allows us to set the valve in ultra-deepwater, which is necessary for emerging GOM reservoirs and applications,” he explained. “These valves have to last a long time and work every single time.”

Looking ahead, Mr Boyle sees equipment trending toward being modular and standardized. “By standardizing and modularizing the designs, we can reduce equipment manufacturing lead time significantly, which means operators can make dynamic decisions about how they want to complete wells.”

Collaboration is playing an important role in that shift, as well. “The wells being drilled today are absolutely challenging current technology, so subsea vendors and service companies have to plan and collaborate on solutions to meet the demands of our customers,” Mr Boyle said. Testing at Schlumberger or customer facilities ensures that the entire system functions as expected before deployment.

“Finally, development of personnel to maximize competency that will increase efficiency in field operations will be a key component to complement the development of evolving technology to meet the demands of the continually challenging subsea environment,” he added. “This will include cross-training in multiple technologies/disciplines and maintaining local experience in specific markets.”

Stringent testing

Hand-in-hand with innovation is a growing awareness of the need for more rigorous testing of equipment and technology. “Operators are wanting more strenuous testing of products because of the environments we’re going into,” said Yvonne McAnally, product line director, upper completions, for Weatherford. “When we talk about risk, a lot is mitigated by stringent testing. If the products fail, the risk is very high,” she said, noting that API is adding more stringent testing and qualification standards for equipment used in HPHT conditions.

Comprehensive testing has been an accepted practice for years when it comes to critically important equipment, such as safety valves. Weatherford did extensive testing in the design and development of the Optimax tubing-retrievable subsurface safety valves, which she points out have never failed since they were first deployed in 2002.

From a safety standpoint, remote or interventionless technology has been a valuable step-change for the subsea market because it reduces the number of people needed on the rig. “Remote technology works in many, not all, instances, but anytime we can remove humans from risk is a benefit,” she said. Weatherford is seeing more operators looking at remote technologies. While the costs of the products are higher than the conventional method, the overall benefit to the operator is greater, and reliability is most important.

“Operators want to be cost-efficient, but they also don’t want to remove the need for ongoing testing and qualifications. It is difficult for many companies to be the first to deploy a new product due to the risk, but this can be addressed by the qualification testing done during development. As an industry, we are always striving to strike that balance.”

Remote tools also can significantly reduce time and costs. “In areas like the Gulf of Mexico, where spread rates are very high, running a plug can add 10 or 20 hours to the operation,” Ms McAnally said. Weatherford is using radio-frequency identification (RFID) tags to remotely actuate various tools, such as barrier valves, production packers and sliding sleeves, eliminating the need for intervention services such as wireline, slickline and coiled tubing.

The RFID-based Keystone system is a tubing-mounted control module comprised of four critical elements: an RFID hydraulic power unit, a circulation valve, production packer and a fall-through flapper (FTF) barrier valve. The remotely operated system can set packers, open packer setting ports and operate sliding sleeves to allow tubing-to-annulus circulation and close and open downhole barrier valves and ball valves.

In late 2012, the Keystone system saved a day of rig time and reduced nonproductive time and personnel costs in a 6,300-ft vertical well in the Middle East by remotely facilitating several tasks, including isolating the reservoir, setting a production packer in 7-in. casing, displacing the completion fluid and then opening the isolation valve to bring the well online.

“With this technology, we’re simply using a module to manipulate existing products without the need for intervention,” Ms McAnally said.

“With the growing number of complex subsea completions, industry is always looking for ways to optimize solutions,” she continued. “At the end of the day, simplifying the process minimizes operational risk and ultimately enhances efficiency.”