Billed by its originator as "A novel system design enabling ultra-deepwater field developments," the NuDeep concept is about moving the game forward for subsea technology.

ABB has been talking about the concept for a couple of years, but is moving some elements into the testing phase hoping to create a new family of four subsea equipment systems for developments up to 10,000 ft (3,000 m) deep and more.

"NuDeep is coordinated to meet future deepwater needs, based on the drivers for deepwater, so that we are ready for further deepwater projects," said Jarle Michaelsen, senior systems engineer, ABB Offshore Systems.

There are a range of elements to the new family, NuComp, for subsea trees and wellheads, NuFlow, for jumpers and manifolds, NuTrols, encompassing subsea control systems and NuProc, a subsea separation suite. The new family can trace some of its lineage to the previous generation Subsis system, deployed in 1,115 ft (340 m) water depth at the North Sea Troll C platform and in operation for 2 years. Subsis processes and re-injects 37,738 bbl of produced water a day.

Michaelsen said the new suite was based on consultations with oil majors who were asked, "What they wanted to reduce the time to production plateau," he said. "The sooner they get to first oil and plateau it gives them cash flow and that's what counts.

"They want to reduce the time to first oil and the time to plateau and reduce the cost of rigs."

Improved production rates and total recovery are part of the picture. Overall, ABB believes NuDeep can offer a 10 to 20% reduction in the time to reach plateau production, and allows second and third generation rigs with less weight-carrying capability to operate on ultra-deep drilling and completion programs, resulting in drilling and completion efficiencies. Roughly 40% of field development costs are for rig drilling and completions, and 25% is accounted for by subsea work and 35% by installation of pipelines and risers, Michaelsen said. "If subsea tendering costs are cut 10%, that is only US $2.5 million on a $100 million project, which is only a little saving."

He then explained that ABB has concentrated on reducing drilling and completion costs, a much bigger prize, typically around $400,000 for a deepwater operation.

At the center of development of this new range of technology is the ethos that all non-essential elements are taken off the critical path to production.

NuComp is a lightweight tree cut from 83,000 lbs to 20,000 lbs weight featuring an ultra-light well barrier system. Existing qualified connectors are part of the new range of easy-to-construct equipment.
This is designed to include a 7-in. swaged tubing run inside a 103/4-in. casing, as a slender production well. Casing features a 11/4-in. annular access and a secondary annular access for downhole communication. Between four and five hydraulic and two to three electrical or fiber-optic connections will be available for downhole utility operations. The system features a slim riser design with a 16-in. outside diameter and has built-in adaptability for heavy casing and dry tree tie-backs. Also, the system is projected to offer between 50% and 70% weight-reduction compared with existing high temperature well technology. Optional remotely operated vehicle (ROV) - installable high-pressure caps, and tubing hanger plug installation and retrieval will be available.

NuFlow is a suite of flexible jumpers featuring weights and buoyancy with an arch configuration between wellhead and manifold and installed by ROV. One end of the jumper is stabbed into a slot on the wellhead and the jumper can then be winched down by ROV to a manifold. They can be lifted at a single point by an installation vessel, and run in vertically, cutting rig time by 40%, it is claimed.
NuTrols offers fiber optics communication connections which are planned for control of hydraulic valves, instrument reading, sensor data, and to relay control commands as well as providing electrical power for valve control.

NuProc is an ultra-compact seabed processing system, featuring slim horizontal pipe providing the separation chamber for liquid separation and up to a tenfold reduction in space requirement. Centralized pumping and auxiliary equipment configurations are possible.

Michaelsen explained the thinking behind the new processing system: In deepwater, one of the challenges is low-drive wells, which can be overcome by substantial water injection. However, at some point this causes water breakthrough in production zones that can kill wells. Hydrates can then easily form in the cold encountered in deep water, hence the desirability of seabed separation to eliminate production water. Also the higher density of water at depth can slow production.

He said gas injection can help overcome these lifting problems, but it cannot work for high water cut wells. Therefore after a shutdown, because deep pipelines work at higher pressures, hydrates can form in less time - 4 hours instead of 8 hours - for example. Therefore the hydrate formation problem can be resolved by removing the water in the multiphase flow.

Consequently NuProc is the technology closest to commercialization because of the potential benefits to deepwater wells with low drive mechanisms. The capacity for NuProc is within the range of high productivity deepwater wells, and operates with a 3-minute fluid retention time. The unit weighs 9 tonnes without any supporting steel work but the target is to keep the weight to 20 tonnes. Framo is the only contractor with a qualified water injection pump which can work with this system, Michaelsen said.
A subsea electrostatic coalescer is used to reduce the water cut from a deep subsea well for NuProc. The technology is based on a vessel internal electric coalescer (Viec) - with a 40 ft (12 m) length of 36-in. pipe, providing liquids throughput capacity of 20,000 b/d with a three minute liquid retention time. "But tests might show we can double that," Michaelsen commented.

Viec is based on the principle of introducing an electronic field into a multiphase wellstream which encourages the size of water droplets in the emulsified stream to increase as they are attracted to either the positive or negative ends of the artificially created electrical field within the coalescer. Consequently droplets become heavier, and fall out of the multiphase liquid more rapidly, speeding up the time taken to remove water from the wellstream. Electrodes are installed on the outside of the vessel, but obviously isolated.

Process engineer Hans Kristian Sundt explained that a Viec coalescer was first installed on Norway's Troll C platform. It is 45 ft (15.1 m) long with 15 ft (4.6 m) diameter unit designed for a 220,000 b/d input load. Results from the unit have given 13% water content in oil although Sundt pointed out separators are designed for specific water cut ranges.

Two Viec plates were installed on Troll C this summer. Work is also underway on developing a more specialized low water content coalescer. "We can potentially save 50% of the weight on a standard module," Sundt said. A smaller unit would consume less chemicals, saving costs, and provide a more environmentally-sound solution. Potential applications are identified for retrofitting to existing topsides; de-bottlenecking, and provide an enabling technology for very heavy or tough oils. Qualification is underway for a high pressure Viec involving fabrication of a test rig and coalescers and power system during the final quarter of this year, leading to test rig assembly and pre-testing next January (2004) followed by high pressure testing to API standards in Houston later in 2004.

At the same time the contractor is looking for operators willing to take the concepts forward into a field trial.

"It will be tough to implement this all in one go," Michaelsen admitted. He suggested the most likely first application will be a low risk well - possibly a water injector in less than 5,000 ft (1,500 m) water depth.
The Viec is an evolution of the compact topside processor, CoSep, a pilot version. It was first tested between first and second stage separators on Triton Energy's Ceiba field floating production, storage and offloading vessel (FPSO) in Block G off Equatorial Guinea last year. A considerable 80% reduction in size and weight was achieved compared to conventional equipment. The Ceiba unit, fitted to an FPSO supplied by Bergesen Offshore, featured a 60,000 b/d separation module and 46 MMcf/d (1.3 Mcm/d - million cu m a day) of gas capacity.

Consuming 400 watts of power, a transformer inside the coalescer boosts power to 10 kilovolts (KV) and higher. One transformer blew up and was replaced, but CoSep has worked well since.
Other designs are for an in-line electrostatic coalescer (IEC), and a lower water content coalescer (LOWACC). An Iec can be built with 14-in. pipe to give a 20,000 b/d throughput. Traditional electrostatic coalescers typically require a pressure vessel with electrodes distributed throughout their length, and a liquid residence time of 10 to 30 minutes for separation to occur, and operational weights varying between 90 and 400 tonnes. They often have limitations on water cut, require liquid levels to be controlled and require high voltage connections. ABB's Iec integrates transformers within the vessel, and water and gas fractions up to 100% are accepted - a much higher water cut acceptance level. Apart from less space and weight, the new separator designs have lower capital and operating costs and have no moving parts or level control. Frequency converters alter the high voltage current required to optimize the coalescing process, and as each unit requires 2kW, during reduced flows, lower power consumption is possible by disconnecting system elements.

Pilot tests of this technology with a 24-in. separator and a controlled emulsion with 15-micron water droplets have resulted in water content at separator outlet between 30% and 0.4% on light 45? API oil, and "similar performance" the company said, with 30? API oil. Heavy oil is also due to be tested in the system and a first application for this technology is sought at a "high discount" the contractor has indicated.

Improvements

Claims of development efficiency improvements of 20% are made for the whole system, while time to first oil is cut by 10% and there is a 10-20% time reduction to reach plateau output. Production can be improved 5-10% while total recovery is improved 15%, according to the company, thus boosting income.
On the cost side of the equation, ABB claims development efficiency improvements of 20% and operational efficiency improvements of another 20%, based on NuDeep performance modeling.
That modeling indicates hard cash improvements up to $35 million, split between $7 million saved on rig time, $5 million saved on company services and a $23 million revenue increase for a 7-well development offshore West Africa with water depths between 2,624 ft and 3,600 ft (800 m and 1,100 m).
The question is who will be the first to deploy it all.