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Abstract A short presentation of subsea processing with focus on the most important drivers that would give high NPV on a prospect.

Operational experience from the world’s first subsea processing station on Troll.

Status from the ongoing Demo2000 project – Subsea Sand Management

Learnings and experience from a JIP in subsea processing with recommendations to how to cooperate between oil companies and supplier industry (AkerKværner, ABB, BP ChevronTexaco).

Introduction As more oil fields are getting to a mature stage, the water content in the well stream will increase. In many cases the water creates a capacity problem on the topside facilities. One alternative is to debottleneck the water capacity of the topside process facility. Such offshore modifications are costly and production stop are needed. . Another problem is that weight and space constraints make it difficult to do modifications. One option for some of these fields is to retrofit a subsea separation station for bulk water removal and injection Commercial drivers for Subsea Processing A number of drivers has been identified for subsea processing. It has turned out that many of these drivers have positive effect, but they do not necessarily create the values that will bring healthy economy to the project. The following drivers are the high value creators

Debottlenecking of produced water Over time the water cut from wells will increase. At a

certain stage the amount of water produced is higher than expected.. Earlier and higher water breakthrough than expected. New discoveries in the area that makes it interesting to extend the field life to extract more oil.

The solution is either to increase the topside water handling capacity or use of subsea processing. Experience tells that the first time around, facilities can be modified at minor cost. Under these conditions the advantage of subsea processing will be that for any one bbl of water that is removed from the well stream subsea, one extra bbl oil can be produced on the host. The limitation of one water injection pump (1.8MW, ∆P180 bar) is about 40.000 bbl/day. Therefore depending on the conditions the increased oil production can be substantial.

Accelerated Production & Increased Oil recovery

When removing water from the well stream, the backpressure on the wells is reduced. This effect increases with the water depth. At 150m WD and 70% Water cut, typical reduced backpressure is 9 bar. At 1000m WD the same backpressure is reduced by 51 bar (Assumption 60.000 bbl/day liquid through 14” riser, GOR 84)

When the wellhead pressure is reduced, the wells will produce more oil/day if the reservoir can allow it. Typical effects are in the range of 10-25% in Accelerated Production

Similarly the reduced wellhead pressure will also make it possible to recover more oil from the reservoir. Typical effects are in the range of 5-10% Increased Oil recovery.

Flow Assurance

When it comes to flow assurance, the issue will be more of a cost reduction in chemicals and capex for corrosion. It will in most cases not be an enabler from a technical term. The reason for this is that the critical issues like hydrates and wax still need to be handled. Subsea processing can make it cheaper, but not remove/solve the problem.

Slugging A benefit with a large gravity based separator tank used for

subsea processing is that in can handle slugs both from the reservoir and the terrain. In situations where the flows are unstable, subsea processing may reduce the problems related to slugging and possible reduced production as a result thereof.

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Enhanced Oil Recovery by Retrofitting Subsea Processing Andreas W. Rasmussen / ABB Offshore Systems

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Hydrates This driver do not come much into place on typical retrofit

solutions with short tiebacks. Existing technology on the power and control side enables tiebacks up to 140km. For such long distances, the saving in chemical consumption can be substantial as there is a direct link between Water content in oil and amount of methanol required. Today’s technology is typically looking at reducing the Water content down to 10%. New technology is looking at bringing this down to 0.5-2%. This will be described later.

There are also another set of drivers, which can give economic contribution, but more on a marginal scale. Increased flow line/riser capacities

Sometime oil production from a field is restricted by the liquid flow in the flow line. In such cases subsea processing can free up capacity in the flow line by removing water.

Reduced produced water discharge – Green effect Most topside processes clean the water to a oil content in the 20-40ppm regimes depending on governmental legislation. The treated water is then dumped to sea. With subsea processing the produced water is injected into the reservoir. By injecting instead of dumping produced water a 40.000 bbl/day with 40ppm oil, a total of 40 bbl of oil per month has been saved from polluting the sea. To improve separation performance, chemicals are often added in the separation. This sometimes follows the produced water and is dumped to sea. Reduced chemical injection consumption

By separating water from the well stream closer to the wells/reservoir, an increased separation temperature is achieved. In addition the pressure can be higher. Increased separation temperature and pressure will in most cases make the separation process work faster and better. For this reason less chemicals like emulsion breakers might be required than in the topside separation case.

Status of Subsea Processing The world’s first full subsea separation and water injection system is installed on the Norsk Hydro Troll Field 80 km outside Bergen, Norway. Located in 350m water depths, about 4 km from the Troll C platform, it has proven to be a reliable system under different operating conditions. This system is designed to flow liquid up to 60,000 bbl/day and can inject up to 45,000 bbl/day of water. It can free up the same amount of topside capacity on Troll C.

The Troll field oil stream is 27°API oil--which is not easily separated. Poor weather conditions most of the year and the field location calls for equipment with high reliability to achieve the required availability of such a system.

The subsea separation station consists of a horizontal gravity separator--where gas, oil and water is separated. The separated water is then injected into a water reservoir, while oil and gas are mixed and sent in the same flow line to Troll C. Two independent level indicators measure the interface levels in the separator. The signals are sent to the topside control system (via fiber optic lines), which regulates the level by

changing the speed of the subsea water injection pump using a closed loop control process. The water-injection pump uses up to 2 MW and can generate a DP up to 180 bars. In addition to the pump and the separator, the system also consist of a water injection tree and a manifold system fitted on the foundation structure. An integrated umbilical provides power (6kV), control, hydraulic and chemicals to the separation station.

The system has been in operation since August, 2001, and

has achieved results that are well within the design specification:

According to Norsk Hydro a total of 4.4 mill. bbl of oil

(Apr 2003) has been produced extra on Troll C due to the subsea separation station. On some days the accelerated production is up to 15.000 bbl/day

A total of 1.8 mill. bbl of water has been injected by the subsea pump.

The subsea separation station has regularity since the start in august 2001 of close to 100%. Prior to this time a repair program was running to handle some teething problems. (This has been indressed in other SPE papers). The only stops that has been in the subsea separation has been when Troll C has required shut downs for maintenance and other reasons. No stop has been because of the subsea separation station itself.

Subsea separation similar to what is on Troll can therefore be said to be proven and reliable.

Under certain conditions the quality of the oil has been lower than expected. When the oil flow from the 5 wells is higher than 24 kbbl/day (Design rate), the amount of water in oil is sometimes more than 10%. The reason for this is under evaluation, but the preliminary answer is that it is related to the shear history of the oil and that the emulsions are particular tough. We believe that there are droplets in droplets, which are difficult to separate.

Ongoing technology programs are making this technology available on deep waters. At the same time test are ongoing to separate heavy oil that very often are found in deep waters like Brazil but also in shallow waters.

The technology that is being tested out is in the area of electrostatic coalescence. These two technologies combined are showing initial results of being able to reduce a typical retention time on heavy oil from 10 min to 1 min. The impact of this is that it gravity based separation systems can be employed on ultra deep waters without having to use super heavy lifting vessels. The product quality of oil can also be improved to achieve 0.5-2% water content. In many cases this could change the hydrate philosophy for a field development.

Subsea Processing and Sand Management On the subsea processing station on Troll, there is a simplified sand handling system. It works by an intervention ROV based system where a flushing skid is deployed and then starts flushing the tank with a jet system fitted in the tank.

Specification Actual Oil in Water Max 1000ppm 15-600ppm Water in Oil Max 10% 3-5%

FJERN FIGUR

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Water is used for flushing. The flushing continues until the sand in the tank is removed. The sand is then brought to the surface for treatment. This system has been tested during integration testing prior to installing the system on seabed. The jetting arrangement in the tank is shown on figure 4.

The reason why Norsk Hydro could choose this simplified procedure is that they have long experience from extracting oil from the Troll reservoir with very limited sand production. In addition Norsk Hydro has good experience with sandscreens fitted on the field

A lot of fields has sand production. This has been identified as a big concern for subsea separation.Demo 2000 Subsea Sand Management is established to look further into these challenges. The project was started in 2001 and is funded by AkerKværner, ABB as the industrial partners and BP, ChevronTexaco and Statoil as Operators in addition to Norwegian Reseach Council. The sand management system has as design basis to handle to different sand production scenarios. Under normal production it shall handle 15mg/m3. Under accidental high sand production it shall handle up to 500mg/m3 The challenges with sand production are several.

• Avoid filling of the separator • Prevent Water Injection well from clogging • Protect Water Injection Pump • Handling of removed sand

Scope in Demo 2000 Perform qualification testing to demonstrate the performance and reliability of desanders, separator sand removal systems and other devices necessary for proper operation. Design and establish necessary documentation on the sand management system on a generic level that can be used for future projects. The ongoing program is split into 4 main focus areas:

Separator flushing Similar methods to what has been used on Troll has been

evaluated and so far proved to function well. The most successful technology in lab test will be built and tested in a pressurized onshore test rig. Different sand removal systems have been tested in lab and they function as expected.

Desanders Perform lab tests to find the most reliable way of desander

for subsea use. The most successful technology in lab test will be built and tested in pressurized onshore test rig.

Sand transport These test are of fundamental nature and involve

understanding how sand is transported in emulsions and in piping and flow lines.

Caking These tests are of fundamental nature and involves

studying the mechanical properties of sand cakes as well their likely location The pressurized onshore test rig will be ready for detail and thorough tests in October 2003. Cooperation and Technology Development The technology development in ABB is done in different constellations. Components and products are developed as JIPs (like SPC and Demo2000 Sand) and inhouse R&D. The following will focus experience from a JIP for subsea processing called Seafloor Processing Collaboration. A co-operation like the SPC where ABB & AkerKværner where approached by BP and ChevronTexaco to participate in a setting to develop subsea separation technology ultimately for deep waters and with long tie-backs, could be very challenging for all parties. The philosophy was that ABB and AkerKværner together should have enough process and subsea competence to develop and build the demanding subsea processing station required. In parallel to the technology development the SPC parties agreed to develop business opportunities for the planned pilot installations. This is a perfect match for fast track technology development and opening up a subsea market fast, which is in all companies interest. After almost 2 years of co-operation one observation is that the market side seems more complicated than expected. Often it is seen that the cooperation between the assets and R&D departments is a difficult interface. This is a trend that has been observed in many oil companies. The implication of this is that traditional portfolio theory is difficult to apply. Theoretically an oil company should analyze its prospects and

Figure 1 - System sketch of subsea sand flushing

Figure 1 - Jetting nozzles inside the separator

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identify what technology is required to develop these fields most economically and then start to develop it. To find a test site should then not be much trouble as it is in the companies’ best interest to have the technology tested as soon as possible before it applies the technology in areas where the whole oil production from a field is depending on 100% availability of the system.

This is often not the case. One reason is that when

debottlenecking is a issue there are a number of alternatives that needs to be evaluated. Questions like another well vs choking back high water cut wells vs topside modification makes the decision not obvious. Another reason for this is that an asset is set up with several other partners with different owner positions and these other oil companies might not have the same priorities on developing new technology and might not be interested to reduce their income from the field in order to test out new technology.

Assets are often only measured on cost budgets and oil production. They have seldom any incitements to try out new technology to the benefit of the whole oil company. From this perspective, they will sub optimize.

Our lesson is that the asset must come in very early, before defining the design basis for the technology development. Both so that you can verify that high specification components are required and that they get the right specification compared to what it cost to develop.

Another lesson is the definition of what is qualified is something each oil company has its own definition of. This is complicated when developing technolohy, as it is not known to what standard components should be tested against. Everybody understands that it is not possible to test each component according to each oil companies “standard”. In the SPC the process of harmonizing the four companies views on this issue has been very challenging and the result is very promising. One critical issue has been in the reliability of each component and system. Traditionally systems have a high failure rate the first few months before it stabilize at a low level before it increases again with ageing. In SPC we have made qualification, test and Quality Assurance procedures to make sure that with 98% certainty there will be no critical failures the first 2 years of operation (Maintenance Free Operating Periods). This is a new way of handling risk. Another aspect in the cooperation is how do two competitors like ABB & AkerKværner work in order to develop new technology. This part has worked very well. Once it is established what each company is responsible for and what should be done 100% jointly (like sand management), cooperation runs smoothly. There where some natural skepticism in the beginning when everybody is careful not giving information about core technology, but once trust was won, true cooperation spirit was achieved. Another pre requisite for the SPC cooperation was that all parties agreed to that the technology should belong to the industry and not be part owned by the oil companies. This applies for technology where ABB & AkerKværner already had established the fundamental technology which new solutions are based on.

Research has been done in the field of how long time products take from an idea to commercial success in different industries. Results from this shows that the oil & gas market is among the slower to adopt new technology. There are several reasons to this. The most important is probably a very conservative industry. On the other hand this puts higher demand on the supplier industry to focus R&D activity products that easily can demonstrate economic benefits for the operators. In this area both oil companies and supplier industry should work closer. The SPC collaboration is an example of market driven technology development to be followed by others when high innovation level is required and no part is very dominant technology wise. Its success (from all parties perspective) depends on that deliveries takes place. This is planned for in 2007. Several new components are under development and will enhance the functionally of subsea processing on different applications.