RUSSELL WRIGHT, Contributing Editor
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| The 3.2 MW, 5,000 psi helico-axial subsea pump from FMC Technologies and Sulzer Pumps completes qualification testing in Sulzer’s custom built subsea test pool in Leeds, UK. Photo courtesy of Sulzer Pumps. |
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Subsea applications have seen explosive growth over the past 30 years. These applications are spread across deeper or more remote fields, as well as being an important route to maximizing production from mature producing fields. As a result, large R&D efforts have been invested in the development of subsea technology covering numerous deepwater provinces such as the of Gulf of Mexico, South America and West Africa, as well as the North Sea. Some innovative subsea developments are presented below, which exemplify the industry’s resourcefulness. A few are still in the design or prototype phase, while others are proven but being utilized in new applications.
AUXILIARY HP ACCUMULATOR
ROV tooling for subsea blowout preventer (BOP) intervention has been limited to small hydraulic pumps that require substantial amounts of time to operate BOP rams. With faster closing times recommended for emergency intervention, supplementary accumulated volume is required subsea. To meet this challenge, the Oceaneering International’s auxiliary high-pressure accumulator system, or Six Shooter, has been developed to meet the 45-sec minimum closing times at maximum allowable surface pressure for ROV intervention systems, Fig. 1. As requirements for secondary BOP stack control become increasingly stringent, operators now have a method for ROV intervention that meets current regulatory rules for matching the primary stack control requirements.
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| Fig. 1. Six Shooter auxiliary high-pressure accumulator system for ROV intervention from Oceaneering International. |
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The Oceaneering auxiliary, high-pressure accumulator system provides a modular, independent source of subsea accumulated volume that can be accessed quickly and easily for emergency BOP intervention. Any ROV of opportunity connects the auxiliary accumulator to the BOP via hydraulic flying leads and industry standard 17H high flow hot stabs. ROV-operable paddle valves on the control panels allow convenient and direct control.
The auxiliary accumulator can supply high flow (100 gpm) control fluid at selectable pressures of 5,000 psi and 3,000 psi, or 3,000 psi and 1,500 psi with its dual-pressure regulators. Its primary module consists of six piston-style accumulators. Each 100-gal accumulator is rated for up to 7,500-psi charge pressure. A secondary module can be easily incorporated into the system if more volume is required. Subsea installation from a service vessel or rig uses a mudmat with a central guide pin, provided as standard installation equipment. A guide funnel assembly secured to the Six Shooter is lowered onto the mudmat guide pin.
The modular, independent accumulator system can be launched and temporarily parked on the sea floor during a drilling campaign. This flexibility allows the operator to forgo costly modifications to the BOP stack and drilling rig. The Six Shooter was designed and built as an independent subsea accumulator system that can be deployed onto a subsea structure (mudmat, pile, existing structure, etc.) and connected to the BOP via an ROV. The unit can override functions in the event top-side communication is lost on the rig. This unit can be launched from a support vessel, IMR vessel, or rig, allowing any ROV of opportunity to function it. Closing times with this equipment can match the closing times of the original BOP stack design specifications. The module is constructed with materials that allow dependable and repeatable functioning over long exposures to a subsea environment.
The primary module consists of six, 100-gal piston-type accumulators, each rated for 7,500 psi. Two regulators allow pressures of 5,000 psi and 3,000 psi to be selected when discharging fluid to function-specific BOP rams. Additionally, a smaller 15-gal bladder style accumulator bottle is in line with each of the two output regulators to act as a surge accumulator. The surge bottle dampens vibration caused by rapid discharge and helps control the output flow in a steady manner.
An API 16D accumulator sizing calculator, which was used for the design of the Six Shooter, is used in the same way a subsea engineer determines how many stack accumulators are necessary for a BOP’s specific circuitry. When utilizing API 16D, the assumption is made that no refill pump on deck was available as subsea accumulators have on standard BOPs, and therefore, the accumulators are optimized so the fluid in the system would be completely discharged. Because the system is dependent on only the available accumulator volume and does not have a refill pump, it is quite large.
After full assembly, the auxiliary high-pressure accumulator system undergoes extensive testing. All pipe and tubing is hydrostatically tested to 1.5 times its maximum operating pressure. Next, the unit is pre-charged with Nitrogen to the desired pressure determined by the API 16D accumulator calculator. The six bottles are not connected by a manifold so that if one bottle has a leak, all do not lose pressure. Therefore, pre-charging the bottles can take a few days, depending on the equipment available to monitor the pressure as they are filled. After pre-charge is set, the unit is charged through its industry standard 17H manifold with control fluid. Control fluid will begin compressing the Nitrogen gas and the pressure inside of each bottle will begin to increase evenly until the desired charge pressure is achieved (7,500 psi max).
Once the unit is completely charged, a test ram is set up on the output of the unit and functioned back and forth using a 4-way valve until all fluid is gone. By knowing the amount of fluid it takes to fully stroke the cylinder the flowrate can be determined. During subsea use, the same events are performed, but charging the unit is done with a subsea pump and fluid is discharged through a hose into the desired BOP function. At approximately 100 gpm and 5,000 psi output, the accumulator system produces flows and pressures no ROV pump is capable of producing.
PURPOSE-BUILT WELL INTERVENTION VESSEL
During the last 15 years, deepwater field development has occurred in ever-increasing water depths, and a significant number of deepwater drilling units (ship-shape or semisubmersible) have been, or are being built to enable this increase. Present water depth ranges for these units are in general some 10,000 ft. Although deeper depth capacity units are available, reality indicates that the number of subsea development wells reaching the 10,000-ft depth is not that high and medium range depths (up to 7,500 ft) are more common. However, reservoir depths up to 30,000 ft are not uncommon today, and completion and intervention of these deepwater wells is a forthcoming and increasing need. Two basic reasons for intervention are:
To address these requirements, a ship-shaped well intervention vessel (WIV) design was developed by GustoMSC, Fig. 2. Its design is based upon extensive experience gained over the last 40 years in designing mobile offshore drilling units, while at the same time, taking into account specifics of well intervention.
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| Fig. 2. Ship-shaped well intervention vessel (WIV) design developed by GustoMSC. |
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A WIV has to be highly flexible with regard to deck space for third-party services. Consideration was given to which well service equipment should be owned by a third party and of temporary nature and which equipment should be owned by the vessel owner. The result is a WIV for deepwater and ultra-deepwater operations, supporting all type of intervention. Also, additional functionality, e.g., top-hole drilling, was created to make investment in the WIV attractive for a vessel owner in view of utilization days.
The WIV classified by DNV as a 1A1 ship-shaped well intervention, dynamically positioned vessel and will be capable of working worldwide with special focus on conditions existing in the Gulf of Mexico, Brazil, West Africa, North Sea and Southeast Asia. Capabilities include:
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Intervention by means of wireline or braided line, or by means of coiled tubing (CT) in combination with a subsea lubricator or a riser-deployed subsea package
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Tubing change-out operations on suspended wells without a riser system (riserless completion running and retrieval)
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Top-hole drilling operations
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Well capping operations with fluid transfer to standby tanker
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Plug-and-abandon work
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Deepwater installation
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Deepwater repair, inspection and maintenance on subsea equipment.
The vessel will contain functional spaces and areas arranged below main deck: propulsion rooms, engine rooms, workshops and stores, switchboard rooms, pump rooms, sack store and mixing area, mud pump room, and accommodation spaces for 150 persons. Dedicated anti-heeling and anti-rolling tanks will be incorporated into the vessel.
The functional spaces and areas above the main deck are the well-testing area; third-party area; riser storage; tubular storage; ROV storage and control; subsea package and Christmas tree storage, testing and handling; substructure, drill floor and derrick; mud-treatment area; subsea facilities (including well control equipment); workshops and store; and accommodations.
The WIV will meet the following dimensions and capacities:
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Maximum water depth: 10,000 ft
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Maximum well depth: 30,000 ft MD below mudline located 10,000 ft below sea level
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Operational condition: wave height between 4 to 7 m at wave peak period of 5.0 to 16.0 s, winds 10 min., mean 20 m/s, current speed 1.5 m/s (3 knots), design speed 16 knots
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Autonomy: 45 days based upon five days mob./demob. and 35 days operation
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Dimensions: 150-m overall length, 28-m width, and 8-m design draft
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Operational loads: 680 mt static hook, 816 mt riser tension, 400 mt crane load, 5,000 mt variable load.
Capacities: 1,800 m3 marine diesel oil, 1,200 m3 fresh water, 1,500 m3 potable water, 1,080 m3 active/reserve fluids, 450 m3 reserve brine and 240 m3 (four pods total) bulk mud/cement.
The primary challenge for the concept of a deepwater intervention vessel is finding a financing model to develop and build the unit. Normally, deepwater units are built against a fixed rate for a set period. In the case of a well-intervention vessel, this is a challenge, since no intervention project spans a number of years. The additional problem is the way in which operators are structured, where no single-point responsibility is present for integrated intervention. A possible way to overcome this is to develop an alliance between a vessel owner, a main third-party service provider and a deepwater technology supplier. Such an alliance could offer an operator a viable option for well intervention activities. The present status for the concept is that presentations and discussions will continue with various interested parties in the industry.
SUBSEA INTERVENTION TOOL
When offshore oil and gas production goes deeper (more than 2,000 m) or into partly ice-covered regions, different techniques and equipment are required for preparatory work, installation, maintenance and decommissioning. Thus, tools must be adapted for conditions far beyond present limitations. Such a scaled demonstration was devised to test the viability of a multifunction subsea intervention tool (SIT), Fig. 3.
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| Fig. 3. Prototype multifunction subsea intervention tool (SIT) under development by Aker Wirth for subsea preparatory work, installation, maintenance and decommissioning. |
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Under development by Aker Wirth, the prototype SIT combines several functions into one tool:
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Automatic seabed leveling via dozer blade or horizontal milling drum
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Five-axis manipulator with a double telescopic 55.8-m boom, 11-mt exchangeable rotating gripper jaws with up to 1,000 Nmm of torque
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Wet matable multi-coupling mounted on a five-axis manipulator for exchange of tools and handling tool forces and tool supply using hydraulics, electronics and signals over a fiber-optic network
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Real-time visualization based on several systems such as USB navigation, CTD sensor, electronic gyro, inclination sensors, green-laser-scanner and pressure measured actuators.
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PTZ cameras and static cameras with image recognition for partly autonomous tool exchange.
Acoustic positioning systems on the sea floor are not only used for positioning but also for communication, e.g., quick-release or emergency shutdown (ESD). The possible autonomous mission planning, in combination with intelligent acoustic navigation/positioning, provides an advantage of moving during limited visibility on seabed between structures. Together with defined safety zones and borders, collisions can be prevented. In parallel, installed subsea structures as well as ROVs/AUVs are presented in real position and in real time via a visualization system. The surrounding seabed is three-dimensionally integrated into the visualization via a bathymetric scan as well as structures, vehicles, etc. The visualization is able to detect possible sliding of SITs on an inclined sea bed.
During installation, systems within a 20-ft containerized control room are located on the support vessel’s deck. The SIT connects itself to a subsea structure and disconnects the lines to the support vessel and is ready for intervention. Also, the SIT can sit on the seabed in standby mode and can be “awakened” for intervention. The control room may also be located onshore.
The SIT manipulator is able to handle hanging and pendulum loads via releasing degrees of freedom. Opening and closing of valves is possible, as well as using the manipulator jaws to steadily drive a revision tool for valve faces. In combination with a subsea tool depot, the vehicle can select different tools for intervention. The SIT was funded by the Federal Ministry of Economics and Technology, Germany.
INTEGRATED PRODUCTION BUNDLE
Total, operator of the Pazflor deepwater oilfield development project offshore Brazil, contracted with Technip and the Subsea 7 Consortium to supply the expertise and equipment that is pushing the frontier of subsea technology. Among several key challenges of the project was the necessity to handle two different oil characteristics, which led to two distinct subsea architectures. First, the Oligocene producing zone, which imposes high constraint on thermal efficiency for such a large field footprint, necessitated the use of pipe-in-pipe (PIP) flowlines and an Integrated Production Bundle (IPB) flexible riser, Fig. 4. A second Miocene zone required the use of a subsea separator.
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| Fig. 4. The integrated production bundle (IPB) flexible riser was developed by Technip to provide high-level flow assurance of hydrocarbon fluids from the well head to surface treatment unit. |
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The IPB, developed by Technip, provides high-level flow assurance of hydrocarbon fluids under difficult conditions (viscous oil, deepwater, pressure constraints, etc.) from well head to surface treatment unit. The IPB is a flexible production riser including thermal insulation layers, additional hoses for gas lift or other services, active heating through electric cables and fluid temperature monitoring with optical fibers. The IPB was first and successfully deployed for Total in Dalia field, offshore Angola in waters between 1,200 and 1,500 m.
To connect the highly insulated PIP loop from the seabed to the FPSO, the IPB riser was the optimum technical choice. While the Pazflor IPBs have no heat tracing cable or optic fiber, but only super duplex gas lift tubes, their design and operating temperatures, 105° and 95°C, respectively, were much more challenging than those at Dalia (60°C). While such temperatures are common for "standard" flexible production pipe, the high level of passive insulation within the IPBs results in an elevated operating temperature of the bundle and intermediate layers of the flexible structure. Material selection was, therefore, key to ensuring that each layer remains within an allowable operating temperature condition. Specific material testing was performed to qualify:
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Bundle fillers that separate the gas lift tubes
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The three-layer polypropylene (3LPP) coating, which protects the super duplex tubes from corrosion
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Anti-wear tapes between the steel armor layers.
Specific qualification testing was performed to demonstrate the leak-proof qualities of the intermediate sheath crimping arrangement under these high temperatures. Finally, a full-scale vertical thermal heat and cool down test was performed on a 12-m IPB sample to demonstrate that the thermal performance fulfills the Pazflor Oligocene field requirements.
To prevent cold spots at the interface between the PIP and the IPB, specifically designed insulation covers were developed to ensure that the minimum cool down time criteria were respected at these connections. Again, this was successfully validated by a full-scale thermal cool down test performed on the overall assembly. Also, given the high temperature under the insulation cover, standard cathodic protection via sacrificial anodes could not be used to protect the flange connection from corrosion. Instead, a sacrificial steel mesh was implemented to consume the limited oxygen renewal within the confined environment under the insulation cover.
Lessons learned from the Dalia IPBs were closely reviewed at the start of Pazflor and mitigation measures were implemented where required. For example, super duplex tube thickness was increased and the filler dimensions optimized to minimize risk of damage to the tube during bundle laying operations. The design of the end fitting, and in particular, the anchoring of the super duplex gas lift tubes, was also improved to ensure that the overall size of the end fitting remained within acceptable dimensions when considering the installation constraints.
Thermal performance of the overall Oligocene loop (35 km of PIP, 2 km of flexible Flextail and 2.4 km of IPB riser) was eventually successfully validated by Total post-installation (full-scale check) through a "thermal performance guarantee test," which consisted of circulating hot dead oil from one IPB and monitoring the temperature of the returning dead oil at the exit of the second IPB.
With the IPB technology, flexible flextails linking the PIP (via dry connection) to the IPB and the manifolds (via subsea disconnect connections) have resulted in considerable schedule optimization and cost saving since the requirement for large flowline end terminations at every PIP extremity was no longer required. 
REFERENCES
1. Lazar, S., E. Shanks and B. Wacasey, “Emergency supply of subsea high-pressure control fluid Six Shooter,” OTC paper 23496, Offshore Technology Conference, Houston, Texas, April 30–May 3, 2012.
2. Klinen, T., S. Knott and H-J. von Wirth, “Subsea intervention tool for deep waters and harsh environments,” OTC paper 23286, Offshore Technology Conference, Houston, TX, April 30–May 3, 2012.
3. Poincheval, A. and P. Gleize, “Frontier Subsea Technologies,” OTC Paper 23177, Offshore Technology Conference, Houston, TX, April 30–May 3, 2012.
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