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Technology Update

Storing Oil on the Sea Bottom to Improve the Bottom Line

Trent Jacobs, JPT Technology Writer

The growing desire of offshore operators to speed up subsea field development while reducing costs has fostered many compelling innovations. Among those systems under development to meet this demand, and one with broad applications, is a subsea storage unit (SSU) created by Kongsberg Oil & Gas Technologies.

The SSU employs the new concept of a “flexible bag” protected by a dome for oil storage on the seafloor (Fig. 1). Depending on field conditions, the dome can be made of concrete, fiberglass, or steel. The system offers oil companies a safer, more cost-effective method of developing subsea fields in extreme weather zones or in the Arctic where ice floes are prevalent. The SSU is also being qualified for extended well testing (Fig. 2) and early production startup, and it may enhance the economics of fields with insufficient reserves to support full field development. Furthermore, the SSU could be used in place of subsea storage cells, fixed platforms, floating storage units (FSUs), and pipelines.

“It is an alternative to existing storage facilities and could also potentially commercialize the development of marginal fields,” said Astrid Rusås Kristoffersen, a subsea systems product and technology manager at Kongsberg. “The [SSU] will increase profitability of marginal fields, because the oil can be stored subsea. And then, using small shuttle tankers for more frequent offloading will precipitate the cash flow and reduce operational costs.”

Ideally, two or more SSUs could be used to maximize the allowable output volume that could be uploaded into a tanker. As production increases, SSUs could be added to the cluster. Kongsberg is considering standardizing the dimensions of the SSU to fit different needs, with the largest version on the drawing board being 131 ft (40 m) in diameter with a capacity of 120,000 bbl of oil.

Subsea storage technology has been used before in limited applications, but never has the design used a collapsible bag to store the oil. The bag is partly made of a polyester woven yarn that is coated with an impermeable layer on both sides to eliminate the possibility of seawater and oil mixing. Were that to happen, an emulsion layer could form, leading to bacterial growth that could cause corrosive damage inside steel pipelines and valves.

Subsea Storage Unit Operation

Openings at the base of the SSU allow seawater to flow in and equalize the pressure. So there is no need to design against pressure and the unit can be deployed to any water depth. The bag can then expand and contract as the volume of oil inside increases and decreases. Depending on the type of soil, a combination of weights, suction anchors, and piles could be used to secure the SSU to the seabed.

The SSU’s intake valves allow the product to flow inside, and once the bag is filled to capacity, the oil can be transported to a tanker through a standard flowline and offloading system. If an operator wishes to use the SSU for chemical storage, the unit would work in the same fashion. Only the source of fluids entering the SSU and the final export flow destination would differ.

If the internal sensors detect a leak inside the bag, they will shut off the intake valves while alerting the operator to the problem. The SSU’s design creates a “double barrier” that protects the environment from exposure to hydrocarbons. “In case the bag should rupture, the outer dome is capable of collecting all the source fluids, preventing spillage into the sea,” Kristoffersen said.

With the dome serving as the second containment layer, the leaked oil can be safely extracted to a sister SSU or discharged to a shuttle tanker on the surface. A removable hatch atop the SSU provides access to the bag and allows easy retraction when replacing
the bag.

The SSU’s weight will depend on field conditions and hydrostatic uplift forces from the stored oil and other fluids. In its base configuration, the SSU is designed to float so that a wide variety of vessels can perform the installation work, which eliminates the need for heavy lift vessels.

Expected Service Life

The dome and shell of the SSU will typically have a service life of 25 years and the bag is being qualified for a life span of 10 years. Kongsberg is looking for ways to extend the bag’s life.

The inspiration for the SSU arose from Statoil’s quest to eliminate the need for surface production systems and put the entire “factory floor” directly on the seabed. “This is one piece of that puzzle,” said Kristoffersen, who added that the SSU also provides a measure of safety for operators who are aggressively seeking new ways to eliminate hazards.

“Currently a lot of oil is stored on FSUs and [floating production, storage, and offloading units], and there is always the risk of collisions with a tandem-loading shuttle tanker. So by storing it subsea, you eliminate that risk,” he said.

During a fire or an onboard explosion, the oil stored in the SSU will not continue to feed the fire. Additionally, if an operator uses several SSUs instead of a floating or fixed storage facility, operating costs will be greatly reduced because subsea storage removes the need for a manned crew or helicopters and boats that provide supplies and transport. Instead, the SSU can be integrated into a remotely controlled subsea production system or a topside production facility that removes the water and gas before transferring the raw crude into the storage unit.

System Flexibility

The flexibility to suit the operator’s field needs is another advantage of the SSU over traditional storage systems because each SSU can be picked up from the seafloor and be redeployed to another field.

If used for extended well testing, the SSU provides another economic incentive by allowing the operator to collect first oil rather than “burning off” the product. Compared with traditional surface storage, the SSU in operation has a considerably lower environmental footprint because the system requires no routine vessel or aircraft support that would emit greenhouse gases.

The SSU technology is being developed for use in the North Sea and is supported by Norwegian oil com-panies Statoil, Lundin Petroleum, and Det -Norske Oljeselskap, and by the Norwegian Research Council. Kongsberg will start laboratory tests in 2014 after which the company plans to begin a pilot program that would include the subsea installation of a full-scale SSU.

The SSU is being designed to meet the requirements of Norway’s offshore regulations and is to be qualified for the North Sea. However, Kristoffersen said, “The SSU is providing a global solution for storing stabilized oil on the seabed.”

Because the SSU is a new design, Kongsberg is offering studies to show the feasibility and concept of subsea storage for specific fields, including the studies of risers, subsea manifold systems, interconnecting pipes, and the control system logic required for SSU operation and process integration with specific offshore infrastructure.

Offset Bow Centralizers Meet Underreamed Well Challenges

Marius Boncutiu, SPE, and Richard Berry, SPE, Centek Group

Underreamed wells are among the toughest challenges to using a centralizer, a device that keeps the casing or liner in the center of a wellbore. Underreaming, the technique of enlarging of a wellbore beyond its originally drilled size, is a drilling method widely used to increase the openhole size, which may be required for various reasons.

Some well planners believe it is safest to drill unknown shallow formations with a small diameter bit and enlarge the pilot hole if no gas is encountered. Underreaming may also be performed if a small additional amount of annular space is desired, for example, if a liner must be run to protect against surge pressures.

A fundamental problem with underreamed wells is achieving effective casing centralization in the underreamed section. The job of the centralizer is to center the casing to improve run in hole (RIH), allow easier pipe rotation, and to enable the cement column to circulate freely around the tubular and produce a robust cement seal to ensure zonal isolation.

Mud displacement is vital to achieving a good cement bond. The more central the pipe, the more efficient the mud displacement will be. In deviated and horizontal wells, if the tubular is not centralized, it will lie along the low side of the borehole and make cement circulation and the achievement of a uniform cement sheath difficult.

Poor centralization can also impair the cement bond by causing channeling, which can lead to various live annulus problems. Like any fluid, cement will take the easiest route in the annulus, and this can result in an inadequate seal if the casing or liner is not centralized. In addition, if the annular clearance is restricted in some sections, backpressure may result that requires a much reduced flow rate during cementation to avoid fracturing the formation and thereby losing fluid.

Offset Bow Centralizer

The Uros offset bow centralizer developed by Centek is designed for use in underreamed or washed-out well sections. The device significantly reduces initial insertion forces and drag when running through previously set casing. Once through this compressed stage, the offset bow centralizer will revert to its designed outer diameter in the open hole and thus maximize standoff without additional drag. The device achieves a reduction in drag compared with other centralizers because of its patented bow design, in which the high points of the bows are offset alternately without reducing the strength of the unit or its capacity to centralize the casing in the open hole.

An oilfield service and product supplier operating offshore Norway has specified the use of the offset bow centralizer in underreamed and deviated wells since August 2011. Even when using two centralizers per pipe joint, the company has consistently been able to reach target depth while maintaining the desired standoff in the open hole. The company is running the device in several fields and has expanded its use to normal wells, because of the fluid and cement displacement benefits that it allows.

Offset bow centralizers are increasingly used in Norwegian offshore well operations. These wells often have a high risk of washed-out sections, i.e., openhole sections that are larger than the original hole size, which are generally caused by soft or unconsolidated formations. However, even in gauge holes, offset bow centralizers are used to ensure high standoff.

Case Studies

A well operator offshore Norway ran 7-in.×9½-in. offset bow centralizers through 9⅝-in. 53.5-lbm/ft casing into an 8½-in. open hole with a total depth of 3600 m. Twice the operation reached a depth of 3560 m before it was necessary to pull the liner. Both times the liner was partially rotated in the open hole on the way in and was rotated for about 12 hours at 20 rev/min in the cased hole on the way out. The centralizers also had to be run through a whipstock window.

Each time after pulling the liner, the drilling and cement teams inspected all the centralizers and stop collars (Fig. 3). The only visible damage was some bending of the set screw sockets. The operator was able to run the same centralizers again and eventually install them at target depth. The offset bow centralizers were run through the whipstock window on five occasions without snagging or packing out on the edges. By comparison, an oversized conventional bow spring centralizer would have exhibited considerably more drag during pullout.

The offset bow centralizers are also being used in various Latin American operations. In an Ecuadorean well, 7-in.×9⅞-in. centralizers were run through previously set 8.535-in. inside diameter casing into a 10.4-in. average diameter open hole. The installed centralizers achieved a standoff higher than the customer’s requirement of 70% along the target zone. In addition, there was less risk of differential sticking, an even annular flow of fluid, and a good well cleanout, with an improved cement job ultimately achieved. The centralization was defined using an analysis of openhole logs, standoff calculations, and liner tally. Centralizers were distributed two per joint along M1 sandstone.

It is necessary to understand the insertion forces and the cumulative running forces, as both affect the RIH performance because the bows are squeezed while passing through the smaller inner diameter of the previously set casing. If needed, the first few joints can be prefilled with mud to increase the string’s weight and enable it to be run in under its own weight from the beginning when less weight is present. This makes it possible to overcome the initial insertion and running forces without pushing the pipe.

In the Ecuador case, when all the casing was run and the liner hanger was installed, the pickup weight was 100,000 lbf and the slackoff weight was 70,000 lbf, which indicated 30,000 lbf of drag. Fig. 4 shows the drag calculation results, which are close to the real values observed while running the casing. In this case, the running force for each centralizer was approximately 1,000 lbf.

There was no restriction while running the liner through the open hole, and the bottom was reached without problems. During circulation, there was no indication of debris accumulation caused by drag. According to the circulation parameters, the well showed a good cleanout. By having acceptable drag conditions when passing through the previously set casing, low drag conditions in the open hole, and maximizing standoff in an enlarged annulus, the offset bow centralizers proved to be a major aid to reaching bottom and obtaining a good cement job in the Ecuadorean well.

Summary of Benefits

Offset bow centralizers result in greatly reduced torque and drag losses, and because they are heat treated, abrasive wear caused by running to depth and rotating the tubular is eliminated. Reducing torque ensures that casings can be rotated without wear in cased and open holes at deeper levels than would otherwise be possible. The ability to rotate a pipe can also greatly assist in mud removal. Typically, a rotational speed of 6 to 10 rev/min is all that is needed.

The centralizers are individually designed to fit each wellbore, rather than generally designed for specified gauge holes. Secure stop collars prevent centralizer movement on run in  or pullout. The choice of a centralizer depends on a number of factors such as the expected flow by area, the desired standoff, the strength and geometry of the formation, the required zonal isolation, the centralizer flexibility needed to traverse known formations, and the estimated start and running forces.

Ensuring a lasting, effective annular seal in the wellbore is vital to maintaining oil and gas production. Preventing water inflow is extremely important and requires good zonal isolation. Achieving a long-term annular seal is difficult, especially in long extended reach wells. The use of offset bow centralizers can aid the cementing process in underreamed and conventional extended reach wells