Ioanna Karra
Roger Knight
Infield Systems Ltd.
The long-term drivers of the subsea market are well known. The relentless depletion of onshore and shallow water fields has compelled oil companies to focus on deepwater areas where a combination of floating and subsea production units is used to extract hydrocarbons. In recent years, this trend has been reinforced by operators favoring technological over political risk, with oil companies preferring to leverage their technological capability in deeper water play than to engage in places such as Iran and Venezuela that have an unpredictable business environment for investors.
Enhanced oil recovery technologies are also being further pursued with techniques such as subsea tiebacks, subsea boosting, subsea processing, and well intervention being increasingly used by operators. Subsea trees have higher costs and lower potential recovery rates compared to dry trees. Therefore, any efficiency gained from treating by-products on the seabed instead of the platform or from minimizing the likelihood of hydrate formation in pipelines can lead to increased recovery rates and hence profit maximization for operators.
This analysis provides an overview of subsea boosting and processing developments. Specifically, we will discuss the key parameters for the adoption of these technologies; the areas where they are expected to be primarily used; the oil and service companies that are involved in pilot and actual projects for these technologies; the risks that these techniques face due to the economic downturn; and, finally, the industry's innate conservatism and the lack of required complementary technologies being introduced.
Subsea processing consists of a range of technologies to allow production from offshore wells without needing surface production facilities. It consists of treating produced fluids upstream of surface facilities on or below the seabed, including seabed and downhole oil/gas/water separation, downhole and seabed multi-phase pumping, gas compression, and flow assurance. The most important benefits from using these technologies include production boosting, improved oil and gas recovery, increased Net Present Value (NPV), reduced surface production facility costs, and the lower likelihood of gas hydrate formation in flowlines.
There are, however, a number of issues that have kept subsea boosting and processing from being used more widely. The most important issue is the reliability of subsea units. They must be able to operate for long periods of time without any intervention. In addition, the consequences from a subsea processing system failure are more severe than those from a topside unit because when a unit fails, an intervention vessel or a drilling rig needs to be deployed to repair or service the unit. This downtime leads to foregone revenue from stalled production and increased costs from securing an intervention vessel or drilling rig.
The two technologies discussed in detail in this analysis are seabed separation and seabed boosting. The latter technology includes seabed multi-phase booster pumps and seabed gas compression.
Seabed separation
Seabed separation involves separating the oil, gas, and water directly at the seabed instead of on a topside facility. This technology is used in mature fields where water production increasingly exceeds oil production and where it becomes economically unviable for operators to continue with the recovery of the field's reserves. The technology can be used also in green fields that have high gas to oil ratios and which face the risk of blocked pipelines because of hydrate formation. Existing and upcoming seabed separation projects show this technology often is combined with seabed boosting. Examples include Statoil's Tordis, Total's Pazflor, and Shell's Perdido Host and BC-10.
Increased water depths and a number of fields tied back to a hub are common key parameters specifying either oil/water or liquids/gas separation. Other parameters are product specific. For oil and water separation in mature fields, key factors include the level of the field's water production and the existence of heavy oil. For liquids and gas separation in green fields, high gas volume fraction, increased distance from the host, and low reservoir pressure and temperature are considered important parameters because the transport of wet gas over 10s of kilometers can lead to hydrate formation and, hence, pipe blockage.
The first seabed separation unit was installed in Statoil's Troll Olje field in 2000, with Tordis, also a Statoil field, being the second field in the world operating a subsea separation unit since October 2007. The driver behind these installations is StatoilHydro's improved oil recovery (IOR) strategy.
Unlike the Troll subsea separation project (which is, at best, a quasi-commercial project), the new Tordis station – provided by FMC Technologies through its subsidiary CDS – is absolutely central to the commercial viability of the whole field. This is because its increasing water outflow was restricting production because pipelines and surface facilities do not have the capacity to transport and handle the extra water being produced in increasing amounts by the well stream.
Meanwhile, Shell recently installed seabed separation units in two of its green field projects, BC-10 in Brazil and Great White in the US Gulf of Mexico. FMC Technologies supplied six subsea separation modules for these projects. At the Perdido Host Regional Development production from the first three fields – Great White, Tobago, and Silvertip – will tieback to a central separation and boosting cluster directly beneath the Perdido Host spar. The fields' key characteristics are their low reservoir pressure, temperature, and great water depth, each of which adds to hydrate potential.
Other upcoming seabed processing projects include gas and liquids separation at Total's Pazflor field off Angola, and oil and water separation at Petrobras' Marlim field in Brazil, Statoil's Fram East project in Norway, and BP's Foinaven field in the UK. The Pazflor project includes three seabed separation units by FMC Technologies to be installed in 2011 and expected to reduce significantly the risk of hydrate formation. The company also will supply Petrobras with a seabed separation unit in 2011 for its Marlim field. To date proposed projects for Fram East and Foinaven have not been awarded.
Infield Systems expects seabed separation units will be used mostly in Brazil's Campos and Espirito Santos basins, in the Lower Tertiary Trend region in the US GoM, in the Northwest European continental shelf (NWECS), and finally in deepwater West Africa.
In fact, West Africa could be one of the key regions for subsea processing because of its already extensive deepwater production, significant oil reserves, and, most importantly, the geographical distribution of fields, whereby multiple discoveries are gradually being tied-back to one central processing facility.
Meanwhile, Infield Systems views the mature NWECS region as a good opportunity for subsea processing technology. Statoil's extensive exposure to Norwegian waters is an important factor for the implementation and future proof of the viability of this technology. That operator has made a strategic decision to increase oil recovery rates from its fields, and subsea processing will be the primary tool to achieve this goal.
In addition, Brazil is an ideal candidate for subsea separation due to the fact that its Campos basin fields hold significant amounts of heavy oil which are more difficult and expensive to extract and process than lighter crude oil. Finally, in the GoM, our attention is drawn to new projects in the Lower Tertiary trend that have both low-temperature and low-pressure reservoirs combined with ultra deepwater.
Seabed boosting
Seabed boosting is at times deployed to ensure the flow of fluids from fields at the required rate after natural reservoir pressure declines. It includes seabed multi-phase and downhole boosting, raw seawater injection, and gas compression. Our analysis focuses on seabed multi-phase pumps and gas compressors. The former is a more "field proven" type of subsea technology compared to seabed separation and gas compression, and they were first installed in 1994 at Eni's Prezioso field. This project was only used as a testing subsea experience for the multi-phase twin-screw pump developed by GE Oil & Gas in the 1980s; it does, however, underline the industry's historical involvement with this technology.
Key parameters that lead operators to use seabed booster pumps include the existence of heavy oil, the increased distance from the host, increased water depth, low reservoir pressure, and a greater number of fields tied back to the host. Several key characteristics are similar for both seabed separation and boosting, and this explains their simultaneous use in some cases.
Seabed multi-phase pumps are separated into two main categories: positive displacement and rotodynamic. From the former category, twin-screw pumps developed by Aker Solutions and GEOG VetcoGray are the most widely used. In terms of rotodynamic pumps, Framo's helico-axial and Centrilift's centrifugal are most widespread.
Multi-phase twin-screw technology is field proven onshore and on production topsides and has also been tested at the seabed: with BP's King project in 2007 being the first commercial implementation. This technology is often used when pumping conditions contain high gas volume fractions and varying inlet conditions. Possible liquid leakage and the limited ability to handle a significant amount of solids represent some of the issues that this technology currently faces.
The helico-axial pump was developed by the Poseidon Group (French Institute of Oil, Total, and Statoil) and manufactured by Framo and Sulzer. Helico-axial pumps are more prone to stresses associated with slugging. However, installation of a buffer tank upstream of the pump is generally sufficient to dampen slugging, so that this no longer poses a problem.
Another technology that has established itself recently in multi-phase production is the electrical submersible pump (ESP) used on the seabed instead of downhole. Seabed and downhole ESPs are manufactured mainly by Baker Hughes-Centrilift and Schlumberger-Reda.
This technology is being used in two Shell projects – Perdido Host and Brazil BC-10 – and three Petrobras projects – Jubarte, Golfinho, and Cascade/Chinook. These pumps are used normally when the pumped fluid is mainly liquid. We predict that ESP type and helico-axial pumps will represent the largest market for subsea processing equipment.
The most important region for subsea pumps is offshore West Africa where eight subsea helico-axial pumps are installed since 2000. The North Sea region and offshore plays in the US GoM and Brazil are also important for use of subsea pumps.
Finally, seabed gas compression involves gas compression at the seabed level instead of gas compression on a topside facility. Key factors driving the implementation of subsea gas compression technology are the discovery of distant offshore gas fields, increased water depths, long step-outs from the host facility, harsh environmental conditions, and low reservoir pressure and temperature. Compared to subsea separation and booster pumps, however, this technology is still embryonic. Infield believe that this is because operators still question the reliability of the system since controlling and monitoring subsea gas compression units over long distances is not as proven a technology as topside gas compression. For instance, power supply to the postulated system on the Ormen Lange field would have to travel by a series of cables over 120 km (75 mi) from the shore to the field.
At present there are no seabed gas compression projects. However, Aker Solutions' pilot program for Statoil's Ormen Lange field is under development. In its later stages, from about 2015, Ormen Lange will require offshore compression to boost gas back to shore to maintain desired production levels as the reservoir's natural pressure declines.
The field is in an area of the North Sea where environmental conditions challenge offshore hydrocarbons projects. In the short- to medium-term, other proposed seabed gas compression projects include Statoil's Norwegian Midgard, Gullfaks South, and Troll Olje fields. From 2018 onwards, we could see seabed gas compressors at Chevron and ExxonMobil's Gorgon project offshore northwest Australia and at Statoil's Snohvit and Gazprom's Shtokman fields.
On Gullfaks South, Framo is expected to use its newly developed seabed wet gas compression technology as part of a two-year development contract the company has signed with Statoil. Framo's technique is different from more established subsea gas compressors and its units are expected to be able to handle an increasing amount of heavier crude oil grades.
Infield views that over the longer term the North Sea and Arctic regions are most likely to use seabed gas compression, in addition to, Russia, Australia, and Egypt.
Operators' involvement
Several oil companies are involved heavily in different subsea technologies, with Statoil and Petrobras the most proactive globally in terms of both pilot/actual projects and qualification programs. This is because these companies are partly state-owned and as such have access to capital to finance new and potentially high-risk technologies as part of national efforts to boost supply to domestic markets.
Other than NOCs, Shell, Total, BP, and Woodside are leaders in subsea processing and boosting. Profitability is key for these firms so the investment rewards and risks associated with new, unproven technologies must involve carefully calculated decision making: somewhat different to national oil companies that are sometimes used by the state as instruments of national energy policy objectives to boost domestic production. Several IOCs, however, have field portfolios that could benefit from such technologies.
Infield predicts that as major operators experiment with subsea processing and boosting technologies – and with time prove their viability (and reliability) – we also will see independent oil companies following suit where field conditions are suitable.
Manufacturers' involvement
Framo, Aker Solutions, GEOG VetcoGray, and FMC Technologies are most highly involved in the manufacturing of subsea processing and boosting equipment.
In terms of seabed multi-phase pumps, Framo, GEOG VetcoGray, and Aker Solutions are relatively well matched in product design and quality, despite the fact that these firms use different technologies. Our view on manufacturers' involvement takes into consideration both pilot and actual projects and qualification programs such as Demo 2000, OG21, and Deep Star. It will be interesting to see how Centrilift's recent multi-phase centrifugal booster pump will compete with Framo, Aker Solutions, and GEOG VetcoGray's established technologies.
On the seabed separation front, FMC Technologies has won the majority of projects. Operators seem initially to prefer to use topside proven separation technology at the seabed – FMC Technologies uses CDS' gravity separator – instead of newly qualified technologies such as those launched by Aker Solutions, GEOG VetcoGray, and Framo. Infield expects the new generation of subsea separation projects will demand more technologically sophisticated methods than those currently in operation.
Conclusion
The number of existing and proposed subsea boosting and processing projects has increased over the last few years. The majority of these units were awarded prior to the recent decline in offshore activity caused by the global economic downturn, pressures on the supply chain, and oil price volatility. Therefore, as a result of the timing of the contracts, several projects have gone ahead despite these conditions. Most operators involved in these technologies are either partly nationalized companies such as Petrobras and Statoil, or oil majors such as Shell and Total. Although several of these oil companies aim for additional cost savings in the short term, we believe there will be a continued effort to push these techniques to improve oil and gas recovery, boost production, reduce the platform's operating cost, and reduce the likelihood of gas hydrate formation in the pipelines.
Subsea processing and boosting technologies are a long-term objective for oil companies that face short-term fluctuations in R&D investment. If these technologies become proven winners that increase NPV they may become the preferred development solution.
The success of upcoming projects is vital to the longevity of the deepwater oil and gas industry. The competition between manufacturers for different technologies, such as the helico-axial and the seabed ESP, is expected to increase. The subsea boosting and processing market is experiencing its first "experimental" stage after which ISL anticipate that these technologies will be used more widely.
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