Deepwater: Seafloor systems push the offshore envelope

JUSTIN SMITH, Offshore Editor

Last month Total’s Pazflor field, pictured here, came onstream. Located offshore Angola in 2,000-4,000 ft of water, Pazflor’s extensive subsea development includes 49 wells tied to an FPSO with over 100 mi of pipe. The gas and liquids produced are separated on the seafloor prior to being pumped to the surface. Image courtesy of FMC Technologies.

Subsea oil/water separation has been used for years to lighten high-watercut wellstreams such as at the mature Tordis field in the North Sea, and pumps on the seafloor—both single-phase electrical submersible pumps (ESPs) and multiphase boosting systems—have helped lift hydrocarbons that low pressure or deep water would otherwise put beyond reach. In the future, resources in Arctic waters, for example, will almost exclusively require subsea developments, as floating ice in the region poses a serious hazard to surface facilities. In the meantime, new development projects and established fields are facing novel challenges that require innovative subsea solutions. At Shell’s Parque das Conchas development in Brazil, a pioneering combination of subsea gas/liquid separation and ESP lift is being used to efficiently produce widely varying wellstreams from three separate fields. Meanwhile, Statoil is trying to extend the productive lives of its mature Åsgard and Gullfaks fields offshore Norway through the use of subsea gas compression, making already profitable fields more valuable.

Supplying power to large fields with multiple pieces of equipment continues to be a limiting factor for subsea developments, especially as tiebacks extend farther out from production units. One major supplier is aiming to solve that problem through a specially designed subsea power grid.

MULTIPLE SUBSEA SOLUTIONS FOR A MULTIFIELD DEVELOPMENT

Shell’s Parque das Conchas development, also known as BC-10 for the block in which it is located, lies in water depths ranging from 4,920 to 6,562 ft and is about 75 mi off the coast of Brazil. Three fields, Ostra, Abalone and Argonauta B-West, have been developed thus far, commencing production in 2009, with a second development phase at Argonauta O-North planned for first oil in 2013.

While the three producing fields may have been jointly developed, they have widely varying fluid properties that required different solutions. As explained by Shell engineer Sada Iyer and associates in a paper presented at last year’s Offshore Technology Conference (OTC), Abalone produces light oil (44°API) with a high gas-to-oil ratio (GOR) of 3,800 cu ft/bbl, whereas the other fields have much heavier oil with lower GORs: 24°API and 274 cu ft/bbl at Ostra and 16°API and 194 cu ft/bbl at B-West. Although the Ostra and B-West wellstreams are more similar to each other than to that of Abalone, geographically Ostra and Abalone are on one side of the development area while B-West is on the other. As a result, one subsea production concept—subsea separation and boosting—is used on the Ostra and Abalone fields, while a separate multiphase boosting system lifts the commingled B-West flow. This artificial lift choice allows the gas to improve the flow characteristics of the very high-viscosity B-West heavy oil. Gas/liquid separation is also used at B-West, but, instead of being produced separately, the fluids are recombined at a controlled GOR, in order to optimize pump performance.

Ostra field is being produced through six wells, and Abalone has one production well, all of which are tied to four caisson liquid/gas separators with ESPs. Once produced fluids enter the caissons, the gas is separated and exported through its own flowline, while the liquids are boosted from the separators to the FPSO located about 5 mi away.

The vertical separation and boosting system, which was designed and installed by Shell and includes Baker Hughes’ Centrilift XP ESP, is enclosed within a very tall caisson, more than 300 ft in height, which is driven into the seafloor like a pile with only a small portion peeking above the mudline. A gas/liquid cylindrical cyclonic (GLCC) separator is positioned at the top of the caisson and the ESP is situated below, within the separated liquid section. Surrounding the pump is a shroud that is used to direct the fluids past the motor to keep it cool, Fig. 1.

Fig. 1. Diagram of one of the Ostra/Abalone separators at Shell’s BC-10 development, with the ESP motor and shroud completely submerged in the fluid portion of the caisson. Image courtesy of Baker Hughes.

Flow from the wells enters the top-end assembly of the caisson and flows through a purposely angled and tangential inlet into the separator. As explained in the OTC paper, “Initial separation occurs in the tangential angled inlet where there is stratification of flow. Further separation occurs inside the main caisson as the heavier liquid is directed to the wall of the separator by centrifugal and gravitational forces. The liquid then flows down the wall of the caisson towards the ESP. The ESP pumps the liquids into a dedicated oil flowline toward the FPSO.”

As for the separated gas, it rises out of the separator into a dedicated gas flowline to the FPSO, driven by its own pressure inside the caisson. Three downhole pressure gauges along the length of the separator are used to measure the changes in pressure and density within the caisson, which indicate to the operators what the fluid level is in the unit. If the level is not within the normal range, the operators can adjust it by changing the speed of the pump in conjunction with a proportional-integral-derivative (PID) feedback control loop.

According to Iyer and associates, efficient separation within a small-diameter unit was necessary to optimize the equipment. This was accomplished through the GLCC concept, which was originally developed by the University of Tulsa in concert with Chevron in the late 1990s.

Part of the reason for the caisson’s great height is to make certain that the pump’s motor, which itself is quite tall, will be completely submerged in the liquid section of the separator and, thereby, kept cool. To keep the fluid speed between the motor and the shroud high, the designers made the passage narrow, but they also had to strike a delicate balance by not making it too tight, which would cause the flow to generate friction that would lower the pressure in the caisson, forcing the pump to work harder.

Meanwhile, the B-West field also has two caisson separators for its two producing wells, but it lacks the dedicated gas flowlines. The gas and liquids are reblended back at the suction of the pump before being boosted the nearly 5 mi to the FPSO via 8-in. flowlines, Fig. 2. As explained by Iyer and associates, “A key challenge in the non-separated caisson is to keep the gas volume fraction of the pump to [a low level]. Higher gas volume fractions through the pump can result in gas-lock of the pump—a condition under which flowrate and boost drop to zero. The non-separated caisson operates on pressure control; i.e., speed of the pump is automatically adjusted by the lift control system to maintain the pressure [in] the caisson.”

Fig. 2. Diagram of the caisson separator used on Argonauta B-West field at BC-10. Once separated, the gas and liquid are reblended at a controlled gas-to-oil ratio before being pumped to the surface. Image courtesy of Shell.

The shroud around the pump and motor in this caisson-separator is designed differently, and is actually what allows the re-blending to occur. At the top of the shroud, which is much taller at B-West, are holes that let the separated gas flow into the suction of the pump. The separated liquid still falls to the bottom of the caisson and up past the motor to enter the pump.

The lynchpin to the whole operation is the ESP, and since BC-10 is situated in more than 5,000-ft water depth, an intervention job to replace a malfunctioning ESP would carry a high cost. As a precaution, Shell and Baker Hughes carried out a number of tests, with the final design being accomplished using Baker Hughes’ Centrilift AutographPC software. Furthermore, to increase the life of the pumps, the caissons at BC-10 capture larger pieces of debris in a junk basket assembly, preventing the debris from getting drawn into the ESP.

PUTTING ON THE PRESSURE

While new developments such as BC-10 are made possible through the application of subsea equipment, advanced subsea technologies are also breathing new life into older fields that are past their prime. Operators active in historically prolific areas such as the North Sea must combat reservoir depletion and rising watercuts. Statoil, which has a number of fields in decline along the Norwegian coast, is putting some of these established subsea techniques to work to improve production in some of these fields. The company is also investigating the use of a thus-far untested method—subsea gas compression—to extend the life and ultimate recovery of others. Although the fields where Statoil is currently planning to use subsea compression are in relatively shallow water, success in these applications will confirm the method’s usefulness also for deepwater projects, where the water depth and lack of infrastructure will be the main challenges to gas production.

Åsgard. In August, Statoil and its partners in the Åsgard development offshore Norway submitted a plan to install and operate subsea gas compression to maintain production from the tied-in Mikkel and Midgard reservoirs. If installed by 2015 as planned, it will be the first gas compression system ever installed on the seafloor—beating out Ormen Lange field, where Statoil has been considering a subsea compression concept since gas production began in September 2007. Åsgard lies on the Halten bank in the Norwegian Sea, about 125 mi off Norway and 30 mi south of Heidrun field. The oil-focused Åsgard A FPSO arrived on the field in February 1999 and became operational three months later. Gas production from the Åsgard B semisubmersible platform began in October of the following year. The field, with a total of 52 wells drilled through 16 seabed templates, ranks among the largest developments on the Norwegian continental shelf.

Analyses show that, toward the end of 2015, the natural pressure in Midgard and Mikkel fields will become too low to avoid unstable flow and maintain a high production profile to the Åsgard B platform, located 25–30 mi away. Low reservoir pressure will provide insufficient power to transport the gas. The installation of compressors on the seabed close to the Midgard wellheads will ensure a high gas flow and recovery rate. The alternative would be to build a new platform with conventional surface compressors, which would cost more and would not increase production as efficiently, according to Statoil.

Comprising the compression unit will be a gas cooler, a gas/liquid separator and a gas compressor, with the latter to be powered by electricity from the Åsgard A FPSO, Fig. 3. An electrical motor will drive the compressor, consisting of a number of vanes around a shaft. The gas will be introduced into the compressor unit at a low pressure, then gradually compressed to flow out at a sufficiently high pressure to be transported through the pipeline to the Åsgard B platform. Installing compression on the seafloor will reduce the pressure where the wellstream enters the seabed receiving installation, which, in turn, will boost production from the field by increasing the differential pressure between the reservoir and the seabed unit.

Fig. 3. Workers hoist one of Aker Solutions’ subsea gas compressors that is being tested for use on Statoil’s Åsgard field. The operator expects that through the use of compressors like this, the life of the field could be extended to 2050. Image courtesy of Statoil.

Statoil has awarded the roughly $630 million contract for design and construction of the Åsgard subsea gas compression system to Aker Solutions. Aker’s scope of work for the system includes a subsea compressor manifold station, subsea compressor station template structure, three identical compressor trains, all-electrical control systems, high-voltage electrical power distribution, topside equipment, and tooling, transport and installation equipment.

Through the use of subsea gas compression on Åsgard, ultimate recovery from the Mikkel and Midgard reservoirs is expected to improve by about 278 million boe, including about 1.01 Tcf of gas and 21.9 million bbl of condensate.
Statoil is also working on other measures to improve recovery in the same area, including reducing processing pressure and drilling and maintaining wells. The company said that it envisions the field to remain productive into 2050. The subsea compression development will also expand capacity in the Åsgard transport pipeline, which carries gas from Norwegian Sea installations to the Kårstø processing plant north of Stavanger.

Aker was also awarded a contract for modifications on Åsgard A to provide electricity to the subsea compression system. The contract, estimated at about $120 million, includes the construction and installation of a new 880-ton module. Saipem will install the compressor and manifold equipment on the seabed, as well as lift the new power module onboard Åsgard A. Still to be awarded this year are various contracts for pipelaying and marine operations, as well as fabrication and installation of a power cable.

Going forward, pipeline installation and marine operations should begin in the second quarter of 2013, followed by the lifting of the electricity module onto Åsgard A in the third quarter of that year. Installation of the actual compressor train is scheduled for third-quarter 2014, with startup expected in first-quarter 2015.

Gullfaks. Statoil hopes the application of subsea compression will enhance the possibility of improving recovery rates and extending productive life in other gas fields as well. While the gas compression system destined for Åsgard is based on Aker’s proven technology, Statoil is taking a slightly different tack with its recovery improvement plans on Gullfaks South field. Discovered in 1979, the 20-sq-mi field contains oil, gas and condensate in the Statfjord and Brent formations and is developed with three platforms. First oil to the Gullfaks A platform came from subsea satellite wells on Dec. 22, 1986. Multiple satellite fields have been developed and tied back to Gullfaks since then.

Since 2008, Statoil and its partners have been working with Norway-based Framo Engineering, which was acquired by Schlumberger earlier this year, to develop technology for compressing wet gas on the seabed at Gullfaks. If successful, the combination of subsea compression and conventional low-pressure production in the later phases could lift the projected ultimate recovery rate from 62% to 74%.

The subsea compression system that Framo has designed is similar to a typical topside system in terms of functionality. According to a paper submitted to this year’s OTC by Statoil’s Tor Willgohs Knudsen and Framo’s Nils Arne Sølvik, Statoil stipulated several requirements for the system, including having two compressors with common suction and discharge lines. As a base, the compressors would need to operate in parallel, but could be set up for series operation. Additionally, the system would have to be able to kick-start dead wells.

The Gullfaks subsea compression system will use three headers to direct flow to the topsides on Gullfaks C, although the number of headers can be increased if necessary, Fig. 4. The produced gas will either be boosted by the two WGC4000 wet gas compressor modules, which will be installed on the manifold on the seafloor, or bypass the compressors and be routed directly to the platform. Actuated inlet and outlet valves will allow each of the WGC4000 compressors to be isolated, while the system also includes protection against backflow through the units.

Fig. 4. One of Framo Engineering’s WGC4000 wet gas compressors is lowered into place in a manifold. Two of these compressors will be put to use on Statoil’s Gullfaks field to add production as natural pressure in the reservoir declines. Image courtesy of Framo Engineering.

In their OTC paper, Knudsen and Sølvik explain that Framo’s WGC4000 compressors are each “designed as a multi-stage contra-rotating, vertically mounted, axial compressor. The compressor section has an inner rotor and an outer rotor. Both are rotating at speeds up to 4,500 rpm. The contra-rotating design eliminates the need for diffusers in the compressor and allows a large number of axial compressor stages to be fitted on a very short length. This favors a short rigid shaft construction that gives solid rotor dynamic behavior. With 21 stages, the compressor also has the advantage of low specific blade loading and good inter-stage phase mixing.”

Installed between the compressor system and the Gullfaks C platform will be a power and control umbilical, which will “provide high voltage electric power to the WGC4000s, as well as small power, signals, hydraulic fluid and chemicals to operate and control the compressor system,” the authors explain. The topsides of the system will be comprised of electrical power supply equipment, control equipment and hydraulic power packs to supply barrier fluid and control fluid to the subsea compressor units.

During the design phase, Framo and Statoil realized that cooling the gas at the compressor inlet greatly improved compression by allowing higher and more efficient energy input into the fluid. Therefore, the system will be equipped with two retrievable cooler units, one positioned upstream of each compressor, to reduce the suction temperature. As an additional benefit, the cooling system helps meet the existing flowline’s temperature limitation of 212˚F.

Testing of one Gullfaks wet gas compressor ran from August 2010 through early May 2011, during which the unit ran for 3,000 hr under a variety of conditions. No major incidents were reported, and Statoil said the results of the test were good. By passing the endurance test and subsequent inspection, the compressor design has qualified for installation.

Meanwhile, in August, Statoil announced the third discovery this year in the Gullfaks South area. As long as the operator is able to keep finding additional reserves in the region, Gullfaks will continue to be an active producer for Norway.

POWER TO THE PUMPS

One thing that all of these pieces of subsea equipment require, regardless of whether they are working on new or mature fields, is copious amounts of power. Supplying and distributing power to the various machinery on the seafloor are often nearly as monumental tasks as pumping production to the surface or keeping pressure up in a reservoir, especially as tiebacks move farther and farther away from FPSOs and platforms.

When moderate or large amounts of power are required—which is often the case for subsea equipment such as ESPs, compressors and boosting pumps—point-to-point cables must be run from the power source in order to run each piece of equipment. A considerable drawback is that these types of subsea cables are quite expensive; according to Siemens’ Subsea Power Systems division, when powering more than one or two pieces of equipment, they have only been economically feasible when covering short distances, up to about 13 mi, although with current advances, that can be pushed to a maximum of about 30 mi, while supplying about 6 MW of power.

Beginning in 2010, Siemens has been working to advance the technology to the point where a high-output, longer-distance power system can be practical in a deepwater environment. The company is aiming to qualify the electrical components to work in up to about 10,000 ft of water, and expects to have a prototype built and qualified, including shallow-water testing, in mid- to late 2013.

The company expects to be able to extend the reach of power to a range of 60–125 mi using alternating current, while powering up to several pieces of equipment with up to 30 MW of electricity off a single power cable. Looking further, by 2018 Siemens expects to be able to push the output range to 30–100 MW while powering about 10 components in a complete grid, and, by 2020, it aspires to be able to deliver ultra-long step outs greater than 200 mi via high-voltage direct current technology that could enable numerous subsea-to-shore applications or allow tie-in of new satellite fields where no existing platform space is available for power systems.

Siemens’ subsea power systems will have three primary components: a subsea transformer will transfer the supplied power to one or more subsea switchgears, which will divide the power and route it to variable speed drives (VSDs) that are connected to the motors on the subsea equipment, Fig. 5.

Fig. 5. The complete subsea power grid being developed by Siemens. The transformer takes power from an offsite location and transfers it to the switchgear, which then distributes electricity to the three variable speed drives that power various pieces of subsea equipment. Image courtesy of Siemens.

The step-down transformer is designed for use with VSDs of pump motors, with a typical power rating of 36 kV/6.6 kV for long-stepout power supply. The base design is hermetically sealed and filled with fluid to compensate for pressure. To keep cool, the transformer will passively transfer its heat to the surrounding seawater.

As for the switchgear, it will contain four vacuum circuit breakers mounted two by two in two separate canisters at a low overpressure. It is designed for a voltage of 36 kV with a three-phase, AC transmission mode. The device is also cascadable so it can handle multiple pieces of subsea equipment. As with the transformer, the base is fluid-filled, but it also houses the main bus bars, wet-mate connectors and measuring transformers.

Finally, the VSDs, which are modular in design as well as pressure compensated, will have a power rating of 5 MW. Multiple drives will be configurable to operate in parallel, in order to achieve higher power ratings. Weighing only about 55 tons, each VSD has a footprint of about 270–320 sq ft. Similar to the transformer, the VSDs transfer the heat they generate to the sea.

According to Siemens literature, the company is combining subsea compensation, through the equalization of internal and external pressure around the power electronics, with the sealing of the equipment for greater reliability. As stated in Siemens literature, “This di-electrical, ester-based, oil-filled concept is a differentiating feature of the development and will virtually eliminate one of the most common failure modes in subsea electrical equipment, water ingress, by avoiding a differential pressure across environmental seals.”

By compensating for the external pressure, the power equipment will also reap the added benefits of reduced weight and deployment cost by avoiding the need for large pressure vessels to hold the electrical drives and transformers.

In order to ensure performance over the 30-year lifecycle for the equipment, the power components will integrate control and instrumentation modules. Siemens says that since a control system allows the equipment to be monitored and controlled remotely, problems can be detected early and resolved before getting out of hand while also keeping production downtime to a minimum, preferably only when maintenance on the system is required as part of planned interventions.

In the development of these power systems, Siemens said it is applying lessons it learned through two earlier developments: the supply to Petrobras of a medium-voltage subsea transformer in 1998, followed by the supply of a “high-current, subsea, magnetic field generation device that has been used as an alternative to seismic exploration.” The first project taught the Germany-based  company how to handle heat transfer requirements as well as how to adapt its onshore high-voltage, long-stepout transformers for a marine environment. From the second project, it gained experience with pressurized electronics base components, such as capacitors and insulated gate bipolar transistors.

A number of challenges still stand in the way of these types of power grids. While medium-voltage wet-mate connectors have been proven and are used today, the high-voltage wet-mate connectors necessary for this type of grid still need a lot of work and represent major challenge. As Siemens literature states, “The current state of the art is limited in the design and qualification of these connectors, and the time to generate a workable solution for voltages as high as 72 kV or 145 kV should not be underestimated.”