NOV’s Subsea Storage Unit takes crude, water and chemical storage to the seafloor, enabling vital cost reductions in marginal and mature fields
As the focus on marginal and mature field development grows, a number of new production scenarios are being developed to meet the challenge. The “subsea factory” approach is by far the most popular and cost-effective in many cases, but operators are still adjusting to some of the more ambitious blueprints envisioned.
Remote production facilities and subsea tie-backs are one thing, but the successful development of small pools will require bold leadership and innovation. Holding 2-3 billion barrels of oil, the majority of the world’s small pools range in size from 5-25 million barrels and lie in water depths of less than 300m. Although tantalisingly in reach, new technologies will need to be embraced if they are to be made economic.
In the case of maturing assets, chemical and/or water injection facilities are often required, again raising potential development costs. Cutting the capital and operating expenditure for such equipment is crucial to keeping older fields running, and enabling new fields to be brought online.
One solution already qualified for use by global oilfield technology firm NOV is the Subsea Storage Unit, or SSU. Developed by the company’s Subsea Production division, the tank enables the safe storage of crude oil, chemicals and produced water on the seafloor, and its scalable and flexible design could play a key role in development, expansion and end of field activities – potentially making small and/or maturing reservoirs profitable. NOV subsea engineer and product manager for Subsea Storage Systems Julie Lund explained to InnovOil: “The storage market of oil is dominated by rental solutions with low CAPEX investments and high OPEX. Floating oil storage units (FSUs) may encounter extreme weather conditions, risk of collisions, pollution, and require large crews and helicopter traffic. There is an industry need for a flexible, competitive and environmentally friendly storage technology, unaffected by harsh environments, winds, waves and seasonal icebergs.”
Beyond the dome While other storage systems may opt for a pressure-resistant tank, this adds to the weight and increases complexity and fabrication costs. Instead, NOV opted to use a flexible membrane protected by a dome. Oil or fluid is injected into the membrane via a hatch in the top of the dome. The membrane holds the stored medium and keeps it separate from the seawater, yet the dome itself is open to sea via free-flow openings in structure. Hydrostatic pressure acts directly on the stored fluid, ensuring that fluid pressure is greater than vapour pressure (which stays at 5 bar or less) and preventing gas separation. The membrane also negates the problem of emulsion layers and bacteria growth, again reducing the need for additional subsea treatment facilities. Multiple sizes provide flexibility according to storage volume required, based on field production data. Single SSUs hold between 5,000 and 25,000 cubic metres (cm) [62,900-157,000 barrels] of oil, at a density of 700 kg/cubic metre to 850 kg/cubic metre. An SSU system would typically consist of one or multiple SSUs connected to a manifold, which are then controlled by an Operational Management System (OMS).
The unit has negative buoyancy, achieved by filling the in-built ballast compartments with sand. Weight piles ensure its stability when deployed on the seabed, although tanks can also be fitted with skirts or suction anchors depending on soil conditions. Because it is pressure-balanced, the SSU can be deployed at any depth greater than 80m – right down to deepwater projects of 3,000m and below.
Deployment itself can be conducted in a variety of ways, Lund said. “Different options have been identified and high-level evaluations have been performed – e.g. subsurface tow through a moonpool, subsurface tow with pencil buoy method or heavy lift… Due to the difference in field specific requirements and location-dependent criteria, a single recommended solution is not adequate.”
According to NOV, oil would ideally be stored at export quality – suggesting that ideal developments would also contain additional subsea treatment facilities.
The tanks have been designed for a typical operational life of 25 years, although storage membranes will require replacement within their 15-year expected operating life, depending on the makeup of the stored crude and the membrane material. NOV could not quote any figures for CAPEX installation without other field study information, but maintained that the benefits of reduced OPEX from crew transfer, long lifetime and the single loading system would all contribute to lower OPEX compared with FSUs or other existing solutions.
The SSU will handle fluids at an inlet temperature of up to 100°C, but additional thermal management options can also be requested for storage which requires it.
Lund added that the unit can be used as an integrated solution for deepwater fields, removing the need for an offloading booster. “It can also be designed as a mobile unit for storage of produced oil during extended well testing (EWT), which represents an economical beneficial and far more environmental friendly solution than to-days ‘burn-off’ strategy,” she noted.
Leakage is mitigated via a monitoring suite in the inlet hatch. If the membrane encounters any fluid leakage, the system will detect the leak and alert the operator of the problem. The dome is then capable of containing all oil inside the SSU, preventing further leakage to sea. Any leaked fluid within the unit can then be safely extracted to a sister SSU or discharged to a shuttle tanker on the surface. The flexible membrane can then be replaced through the hatch on top of the dome.
Fluid scenarios In addition to oil storage, the SSU is also designed to handle chemicals and produced water. During development, modifications were made to produce a unit suitable for the storage of fluid with greater density than seawater, such as mono ethylene glycol (MEG), a chemical used to prevent hydrate formation and remove blockages. Typically, chemicals may need to be pumped via long umbilicals to reach the point of injection at the wellhead or pipeline. The SSU forms one vital part of the infrastructure required to site anywhere between 50cm and 25,000cm of chemicals or water on the seabed, either close to the production platform or next to the subsea wellhead. In addition to reducing the complexity and costs of umbilicals and associated equipment, storing MEG subsea also frees up space and weight on topsides and improves safety by removing the potential hazard of explosive materials.
In the case of produced water, the design can be configured to separate water as a settling tank or a flotation/buffer tank for discharge to sea or re-injection into well with a water quality of 30 ppm or lower. NOV notes that by performing separation subsea, the pressure loss in production flowlines is kept to a minimum, enabling a lower wellhead pressure that can also lead to increased production. In a re-injection case, the produced water will also maintain pressure in the well, ensuring optimal production. In turn, this can reduce the need for topside process equipment, and help operators comply with environmental regulations on discharged water.
Opportunities NOV evidently sees opportunities as fields mature. Lund told InnovOil that further refinements to the system were already in the works to meet new challenges. In particular, she said: “An adaption to the Subsea Storage Unit (SSU) is proposed to be specifically optimised to smoothen out variations in liquid content, and to achieve settling of solid particles and flotation of oil droplets by gravimetric separation…to achieve required water quality of 30 ppm or lower for discharge to sea or produced water well-injection.”
NOV is currently working with Chevron, Statoil and Woodside on a qualification programme for the Produced Water Treatment System, the first phase of which was completed June 2017. Phase two will begin in the autumn, and is open to additional operators and sponsors.
The purchase of Kongsberg Oil & Gas Technologies’ subsea production portfolio in September 2016 also adds new possibilities to NOV’s offering, including new technologies for subsea storage, process and tie-ins, Lund said. While further analysis will be required before these refinements are complete, NOV already has robust and flexible systems to help make mature or marginal assets more attractive – it is now up to E&P firms to make bold commitments towards bringing these developments online.