Sizing and Selection Criteria of Subsea Processing Technology

An OGE project course by: Wenting LiDi LaoTai LeHoussemeddine LeulmiSaleem MubasharHaris Sikandar

Course instructor: Supervised by:

Dr. Faisal Khan Dr. Thormod johansen

Table of ContentsIntroduction of subsea processingOverview of subsea processingHistory Benefits of subsea processing and candidate fields for the technologyReal life applications for subsea processingSubsea processing installation challengesSubsea PumpingIntroduction of multiphase pumpCurrent subsea pumping technologyThe market of subsea pumping systemSubsea Separation SystemIntroduction of subsea separationFirst technology of subsea separationCurrent technology of subsea separation for deep waterGas CompressionIntroductionChallengesTechonolgyDecision design for subsea processingDecision making parametersDecision making scenariosSummary of workFuture workReference

Table of FiguresFigure 1: Effects of current of shape of lowering the rope 9Figure 2: Deep water installation methods . 10Figure 3: Centrifugal Pump . 12Figure 4: Helico-Axial Pump . 13Figure 5: Electrical Submersible Pump 14Figure 6: Twin-Screw Pump . 15Figure 7: Subsea Pumping Market . 15Figure 8: Example of horizontal subsea liquid-liquid separation from FMC Technologies . 17Figure 9: Example of vertical gas-liquid separation from FMC Technology . 18Figure 10: Example of cyclone separator from FMC Technology . 19Figure 11: Example of Caisson Separator from Baker Hughes . 20Figure 12: Components inline in gas-liquid separation from FMC Technologies 21Figure 13: Components inline in liquid-liquid separation from FMC Technologies . 22Figure 14: The example concept of pipe segment separation from FMC Technologies . 23Figure 15: Gas Compression Figure 1 Well stream compression . 24Figure 16: Gas Compression Figure 2 Conventional design gas compression .. 25Figure 17: Example of short distance tie-back subsea configuration 27Figure 18: Example of medium distance and long distance tie-back configuration .. 29

1. Introduction of Subsea Processing1.1. Overview:The basic and simplest definition of subsea processing is that the processing components or facilities on the platform, FPSO or onshore is moved to the seabed. Subsea processing comprises of several components such as: subsea pumping, subsea separation system, subsea gas compression/boosting system, subsea water re-injection system, and subsea powering and control system. However, in this project, as power or controlling unit is not in our interest group and re-inject water system is just the design or select the pump for produced and separated water, we mostly will focus mostly on: Subsea pumping, Subsea separation system Subsea gas compression

1.2. Subsea processing development technology history:The subsea processing technology has gain much interest in the oil and gas industry as its promising advantages for deep water challenges. Subsea processing is still on academic research until 1990s. Many million dollars were investigated in subsea pumping and separation from 1970-2000. However, the real application with subsea processing has not been started because of many reasons. There are many technical issues with the design and operation that have not been solved. Besides, the uncertainty about the cost and benefits when applying the technology holds back the technology to be utilized in real industry as well as the inexpensive of topside processing facilities which can give a reasonable feasible economyHowever, as the driven force of deep water exploration and production, many challenges such as: flow assurance, high viscosity, etc. have given the boost to subsea processing technology as the industry wants to recover more oil. The challenge to recover oil becomes more and more difficult from small mature uneconomic field and deep water field has put the subsea processing technology in real industry application. As the subsea processing technology contains: subsea pumping, subsea separation and subsea gas compression/boosting, each history and progress of each technology is not on the same pace. The original and traditional of subsea processing only contains the multiphase pump which is installed close to the well without the separation to add energy to produced fluid on the seabed to exceed the frictional and hydrostatic losses from the flowline and riser to the platform or onshore facilities. However, the limits of the multiphase pump are applicable in shallow water with short tie-back distance as well as incapability of handling large gas volume fraction. Then the subsea separation is introduced to reduce the duty of the pump and high gas volume problem. Up until now, both subsea pump and subsea has been extensively developed.1.3. Benefits of subsea separation and candidate fields

1.3.1. Advantages: There are many advantages applying subsea processing: Platform (save money): Because of the processing facility is moved from onshore or FPSO to platform to subsea, a lot of space on the platform will be saved and smaller platform also means less money spending for the platform. Second, the harsh environment doesnt give the option to have processing on the platform or FPSO. Third, as handling water offshore on the surface is typically more expensive and require large and expensive facilities. Pressure (save energy, more money): Low pressure is encountered with brownfield reservoir. Another problem is deep water with long tie-back will result a lot of pressure loss. Subsea pumping and separation as parts of the subsea processing can provide large pressure drawdown. Besides, subsea separation can separate the water and sand at subsea and re-inject or dispose. So the production liquid needed to be lifted are composed of only oil and gas, instead of oil, gas, water and maybe solid. So the duty of the pump required in subsea will be smaller instead of the pump on the FPSO It can help to manage pressure problems with heavy oil reservoir Flow assurance: better flow assurance Hydrate: As water is mostly removed or gas is separated from production liquid and flow alone, the chance and volume of hydrate can form during the pipeline transportation is reduced greatly Slugging: It happens with multiphase flow. After separated, the liquid production flow separately in different pipe, so the slugging by multiphase doesnt happen (unless gas is combined with oil to flow together in short tie-back distance without the appearance of subsea separation in the system) Increase production and improved oil recovery Subsea separation and pump contributes to reduce wellhead pressure and therefore facilitates that more oil and gas can be produced faster from the reservoir which can increase the field economy

1.3.2. Candidates field to apply subsea processing technology.The application of subsea processing technology can be utilized by different type of reservoirs with different challenges such as: managing pressure problems with heavy oil, and flow assurance like hydrate or slugging. The first and original candidate will be deep water reservoir as the technology is made to overcome difficulties from deep water. Second, the reservoir facing with high water cut and restricted topsides place can utilize the subsea processing technology for the field development. Third, low reservoir drive mechanism or low pressure reservoir is another suitable candidate for the method. Lastly, any reservoir remote field with long tie-back distance or harsh environment/extreme weather can be beneficial from the technology1.4. Real industry application example: There are many fields utilizing the subsea processing technology. These are two examples of famous real fields which apply this technique1.4.1. Tordis field (by Statoil company and FMC Technology)Tordis field is the first field that applies the initial subsea process which includes: subsea separation, subsea boosting and injection system which marks the first practice of subsea technology to the field. The field is in North Sea with the depth of 200m (shallow water) and has been operated since 1994. The first problem encounters is the low pressure in the field so that it is not sufficient for oil and gas flowing from the subsea well to the surface. The field becomes aging and maturing with the increase of water production (up to 70-80%) and large amount of sand (500 kg/day or 1,102 lb/day). The amount of water produced are larger the amount of onshore facilitys transport and handling capacity. The FMC Technologies has successfully applied subsea separation, subsea boosting and injection system (SSBI) to the Tordis field to increase the total recovery and extend the life of the field. The subsea facility is able to manage 190,000 barrel of liquids at 500 psi operating condition. The subsea separation can get rid of water up to 100,000 barrel with standard cleanliness (1000 ppm of oil) and 35 million cubic feet of gas per day by the cyclone separation. Besides, the separator is also designed to eliminate 1,100 lb of sand per day. Then the water and sand will be mixed and re-injected to the field. Because of the subsea process facility, the Tordis field has increased the recovery from 49% to 55%, adding about 35 million barrel of oil to the recovery and extend the life of field to 15 years. For this project, despite the initial idea of subsea process which is for deep water field, it is also useful and applicable for shallow water field which encounter common problems such as: aging and maturing.1.4.2. Marlim field (operated by Petrobras in Brazil)Marlim field was the largest field in Campos Basin offshore Gulf of Mexico, Brazil operated by Petrobras. The depth range is from 2100 to 8500 ft (650 to 2600 m). The field has been operated since 1991 and considered the worlds largest subsea development with more than 200 wells (129 still active today). The drive mechanism of the field was gas solution drive and water injection is used for secondary recovery.The estimated reserve is 9 billion barrels. After 20 years of production, the field has become maturing and aging with declining reservoir pressure and large amounts of water in production system. The heavy oil was encountered for this field as the oil API ranges from 17o to 24o as well as sand production. The high viscosity of oil and sand presence made the problem more complex for the field. The normal solution to address the problem was extending the existing field separation capacity. However, still large amount of energy was required to lift high volume of water and damaging sand from the seafloor to the FPSO.The Marlim has chosen subsea process and become the first deepwater subsea heavy oil/water separation system for a mature field. It is the first time that subsea separation is used in deepwater aging field to separate heavy oil and reinjection the water back to the reservoir. The project started at 2011. The subsea separation, subsea pumping and re-injection system is placed at 2950 feet (900 meter). The whole produced fluids which contain heavy oil, gas and water will go to the separation system to separate gas from the liquids first. Then the water will be removed from heavy oil. The InLine HydroCyclone and Desander modules will take care for water and sad management. Gas will combine with heavy oil later to flow to the platform while water flows through pump back to the reservoir. The subsea process opens a large potential for the Marlim field. With the increased only 1%, 90 million addition barrels will be recovered.1.5. Subsea Processing Installation Challenges.1.5.1. Lifting and lowering issues:This addresses the issues related to the weight of the loads to be lowered on the seabed, the dynamic responses from the seawater and the capability of lifting technology used. As the responses from sea water may interfere in the operation (Figure 3), the first matter of concern is the material of construction of the rope used to lift and lower the load. Several options can be considered in this regard. Conventionally steel wire ropes are durable for subsea lowering but they are partial in their application to deepwater. At very large depths, the ratio of weight of the rope to the weight of payload might become a problem and when we go further deep the safe working load is entirely taken up by the weight of the rope itself. Another problem can arise due to free rotation of the rope. The free rotation can vary between 100 600 deg rotations per meter[10]. This difficulty is of substance mostly when the load is released and the rope attempts to unwind. The shape and size of the load being lowered may also pose a challenge considering the fact that it might contribute to an added mass and in turn, added weight because of water entrained around it. When lowering heavy structures on long lifting lines, there is also a major hazard of resonant motion between the oscillating surface vessel and the lifting system. This can initiate large dynamic forces and result in failure of the lifting line[11]. Another issue associated with installations under water is that as the depth increases, strong currents can affect the shape of rope introducing a greater offset. A number of options have been discussed and experimented to meet these challenges. To encounter the problem caused due to increased self-weight in case of steel wire ropes, material of construction with neutral buoyancy have been introduced. Synthetic fiber ropes provides a reasonable solution to this problem but it has a limitation associated to its low melting point. As the temperature drops significantly under water, it may cause the synthetic fiber rope to melt. To face these challenges several other options have been proposed like the use of spool-able compliant tubular, the free-fall installation method and subsea deployment system etc but the verdict depends on the load to be lowered, the behavior of sea water and the specific properties of the lifting rope[10].

Figure 1: Effects of current of shape of lowering the rope

1.5.2. Load control and positioning This highlights the questions related to placing the load at the desired location and its stability on the seabed. Challenges associated with load control and positioning will augment at larger water depths. As the depth increases, one problem can be a very large offset between the surface facility and load being lowered caused due to water currents. If we take into account the resonant region, where the dynamic forces may have a maximum influence, the preferred method to overcome this region is to lower the load as quickly as possible through this region. But when the loads are lowered at greater speed, the unstable lateral fluid forces may disturb the load and force it to slide away from the desired position. Deepwater soil conditions are also likely to be very soft and bearing capacity failure of the seabed under the load may be caused which in turn will result in an unstable or undesired orientation of the load. One crucial element in load positioning is the release mechanism of the load from the hook. Since the hook will become less manageable after the tension is released, problems may occur if it is entangled to the released load.Figure 2: Deepwater installation methods

1.5.3. Metocean effectsThis underlines the challenges occurring due to weather, winds, waves, currents, water levels, temperatures and other metocean conditions and their effect on the subsea installation operations and the pace with which jobs must be performed. When dealing with the subsea installations, it will take longer to lower and position the equipment to the seabed and longer to raise the lifting gear afterwards for the next lift. When lowering process is speeded up, the problem arising is that whether the load can actually be made to sink at higher speed without sliding off position and landing at a point other than the desired. Again the factors like the shape of the load being lowered and the hydrodynamic forces acting on it need to be considered[10].

2. Subsea Pumping/Boosting2.1. Introduction:The subsea pumping or boosting is considered the first technology of subsea processing. The technology has been extensively studied and developed for many years. The original purposes of subsea multiphase pumps are to provide enough energy for produced fluid to overcome the frictional and hydrostatic loss to transport from the sea level to the. There are many advantages of using multiphase pump or boosting such as: accelerating and increasing production; stabilizing flow in wells which cant flow naturally due to low pressure or remote distance; reducing the well intervention cost and subsea development cost; enabling to produce oil and gas in harsh environment; eliminating offshore flaring; reducing back pressure at well head; reducing the size of the topside facilities, etc.However, as the demand of extracting of in deeper and deeper environment, the technology of multiphase pump has some limitation which cant handle the long distance tie-back due to higher pump duty and higher pressure loss as well as large gas volume. So to overcome these problems more and more advanced technology have been introduced such as: centrifuge (single phase pump), helico-axial pump, twin screw pump, electrical submersible pump (ESP) and hybrid pump (centrifuge and helicon-axial pump). More description about these technologies would be discussed in the next section2.2. Current subsea pumping technology:2.2.1. Centrifuge pump (one-phase or single phase pump):Centrifuge pump is a single phase pump which can provide the highest pressure differential among all pump types (up to 350 bar or 5000 psi). However, it can only handle with relatively low gas volume fraction (less than 10-15%) in suction conditions. The centrifuge pump is used in mature field or low pressure or reservoir energy drive. It can be used to pump for water flooding or re-inject separated water method to increase reservoir pressure and recovery.

Figure 3: Centrifugal pump (AkerSolution)

2.2.2. Multiphase Helico-axial pump (HAP):The multiphase pump, as mentioned above, can improve production by reducing backpressure of the reservoir which can help to increase flow rate and total recovery. The helicon-axial pump is able to handle large gas volume (from 35 to 95% at suction condition) as well as provide a reasonable high differential pressure (200 bar). Besides, it is simple and has low-cost intervention advantage compared to other pump types as well as its moderate particulate tolerance (70 mm to 400 mm diameter of particles). However, some disadvantages of helico-axial pump can be addressed as: high shear and slugging problem. Besides, it is also not a good choice for high viscous fluid (heavy oil), low flow rate or low suction pressure. The design of HAP mostly is vertical configuration.

Figure 4: Helico-axial pump from Framo, 2013

2.2.3. Hybrid pump (centrifuge + helico-axial):Hybrid pump is considered as the combination of centrifuge pump and helicon-axial pump together on a common shaft to bring out both of the advantages of these two pumps. It is able to have moderate amount of gas volume at suction conditions (25 38% GVF) as well as high differential pressure (200 bar) as well as the ability to pump highly viscous oil.

2.2.4. Electrical Submersible Pump (ESP):The ESP pump modular consists of a driver unit and a pumping unit. The driver is installed upstream of the pump to be cooled by passing liquid. The driver can be either an electric motor or a water turbine. The pump itself is not designed to handle high GVF, because the electric motor is cooled by the passing liquid. ESP is an option at a flow rate range from less than 1,000 BFPD to 20,000 BFP and in the future of down-hole applications; for example in ultra-deep wells (10,000 ft) to drive the fluid to the seabed. After boosting fluid to the seabed, other pump methods (like HAP or TSP) can drive it to the host facilities. ESP in series installation can provide enough differential pressure to boost fluids to host facilities

Figure 5: Electrical Submersible Pump from E&P 2013

2.2.5. Twin-screw pump (TSP):This type of pump is designed to handle high viscous liquid with low shear that is not possible for HAP. The speed is directly derived by suction lift and viscosity. The pump doesnt pull the fluid inside; suction pressure is necessary to push that inside. However in a subsea application, which is located close to the wellhead, it would not be a problem. The suction lift shouldnt be underestimated, because it may result in the pump operating at lower speeds. It increases the cost because of a larger low speed pump and driver. TSP is designed for vertical and horizontal installation, while HAP is only available in vertical design

Figure 6: Twin Screw Pump from Borenemann, 20132.3. The market of subsea pumping:Figure 7: Subsea Pumping Market from MarketsandMarkets AnalysisUp until this date, the most popular subsea multiphase pump: Helico-axial pump, electrical submersible pump and centrifugal pump are the most commonly used in the oil field industry3. Subsea Separation System:3.1. IntroductionOne advantage of separation technology is that it can separate water from the produced fluid to re-inject back to the reservoir to maintain the reservoir pressure. Besides, as introduced above the subsea separation technology has made the appearance in the subsea processing technology because of the limitation of traditional multiphase pump. The purpose of the subsea separation is to reduce the duty of the pump as well as to prevent the possibility of degrading of the pump due to solid particles.3.2. Subsea separation technology There are many type of oil and gas separation. The concept of separation onshore or on the platform makes no difference from the separation from the seabed. The main difference is that the requirement of compact size, high reliability and same efficiency are required when designing the subsea separation due to the hoisting and maintenance difficulties as well as water depth. However, reducing the size of separation mostly makes the separation performance also lower as well as its ability to handle the changes in flow rates and composition. So finding the balance point to handle the separation performance as well as compact size is critical for subsea application. The first subsea separation technology can be divided into 2 big categories: liquid-liquid separation and gas-liquid separation. Both of them are considered as gravity based separators but with different applications for different scenarios.3.2.1. Subsea gravity based separator:Gravity based separator is considered the first subsea separation technology which can be divided into 2 big categories: liquid-liquid separation and gas-liquid separation. It is the first trial of using the separation technology from onshore to apply to subsea scenario. However, there are some disadvantages which hold back this type of separation to apply for deeper and deeper water. The first and obvious one is the size of the gravity based separation. Any gravity based separation are made to large vessels which can only be limited to use to shallow water, not deep water. Second disadvantage is that gravity based separation allows only or little to no change to what it can handle. Liquid-liquid subsea separation:Liquid-liquid separation is usually designed as a horizontal separator to mostly separate oil and water from the reservoir fluid production. The examples of subsea liquid-liquid separation can be found in Troll C Pilot of Tordis SSBI projects. The concept is to separate and re-inject the produced water. The concept is to reduce the backpressure by reduced the fluid gradient to increase the production and improved recovery. It also helps to eliminate the requirement of separation water onshore or on the platform/FPSO which usually results in high cost. The liquid-liquid separation is beneficial for Oligocene reservoir in which the fluid is characterized as less viscous oil.

Figure 8: Example of horizontal subsea liquid-liquid separation from FMC Technologies Gas-liquid subsea separation:Gas-liquid separation, in opposite, is designed mostly as a vertical separator to separate gas from liquid produced. The example of subsea gas-liquid separation can be found in Pazflor or Shell BC-10 projects. The gas-liquid separation is its ability to handling solid and slugging problem. The gas-liquid separation is beneficial for Miocene reservoir which is characterized with more viscous oil (heavy oil), low gas fraction and low reservoir pressure.

Figure 9: Example of vertical gas-liquid separation from FMC Technology

3.2.2. Cyclone Separator:The concept cyclone separator is based on cyclonic rotation which acts similarly as gravity force to separate heavier particles or liquid phases outward while the lighter phase remains in the middle section. The induced rotation generates forces greater than gravity. It is composed of an entrance, body and two exits which can only be used to separate 2 different flows. Cyclone separator is in compact size and mostly installed before the inlet of gravity base separation to separate gas from produced fluid before entering large vessel separation to reduce the separation duty and enhance the gas phase separation.

Figure 10: Example of cyclone separator from FMC Techonolgy

3.3. New and currently developing technology for deep water challenge:Due to the demand and challenges of extracting oil from deeper water, it is not feasible to have large structure of liquid-liquid separation and gas-liquid separation as in Tordis or Pazflor scenario (only installed at 200 and 800 meter respectively). As going deeper and deeper in the ocean, it is essential to develop or change the separation design as more compact and more efficiency separation3.3.1. Caisson separator:This type of separator is considered as the first attempt for deep water reservoir. It is used in Perdido field and Shell BC-10. The Caisson separator comprises of building blocks which can be used at extreme water depth. It is also considered as gravity based separation. However, because of the limit in performance efficiency, inability to handle sand, low capacity and high cost of drilling or preparing dummy well, this technology doesnt seem the optimum solution for deep water. So other new separation technologies has been developed and introduced to the topside and wait for the compact version for subsea usage.

Figrure 11: Example of Caisson Separator from Baker Hughes

3.3.2. Other currently onshore developing separation technology: Due to the demand of separation technology for deep and ultra water, other onshore separation technology could be considered to develop for subsea application. Some of them are: inline separation technology and separation in pipe segments instead of in large vessels

3.3.2.1. Inline separation technologies:Inline separation technology inducing swirl flow which yield the high efficient separation, either by high G force caused by cyclonic flow or by electrostatic coalescence. The phase separation is achieved in the pipe spool with similar diameter as the piping up and downstream separator. It has an ultra-compact size. This can be applied for gas-liquid separation, liquid-liquid separation and solid removals. Some main components as well as its simple purpose are listed below: Inline Gas-Liquid Separation: Inline de-gasser: to separate gas from liquid Inline de-liquidiser or Inline PhaseSpliter: to separate liquid from gas or separate two uniform phases Inline de-mister: to remove small droplet from gas stream for enhancing quality of gas Inline Liquid-Liquid Separation: Inline de-water: to separate water from oil (less than 50% water cut) Inline bulk de-oiler: separate oil from water stream (less than 50% water cut) Inline electrocoalescer: to increase the size of water droplets in oil, used in upstream gravity separator with light oil or heavy oil processing Inline hydrocylone: to separate oil from water to low level, used in water treatment Inline Solid Removals: Inline de-sander: to remove solid from liquid, gas or multiphase stream

Figure 12: Components inline in gas-liquid separation from FMC Technologies

Figure 13: Components inline in liquid-liquid separation from FMC Technologies

3.3.2.2. Pipe Segment Separation:The pipe segment separation uses gravity in small diameter pipes which doesnt take a lot of space which making the whole structure easy to manufacture and lighter. The efficiency of the pipe segment separation is more efficient because of the flow conditions in the pipe. This pipe separation technology can be applied for gas-liquid. The technique is suitable to separate difficult fluids. However, the sand handling might be a challenge for this type of technology. Besides, only pipe diameter is reduced but the whole system still bulky to the challenge of the deep water

Figure 14: The example concept of pipe segment separation from FMC Technologies

4. Subsea gas compression/boosting

4.1. Introduction:Subsea gas compression/boosting is an alternative to a compression platform for boosting the gas condensate where the natural pressure of the reservoir cant support the flow of gas naturally. The economic opportunities and technical feasibilities of subsea gas compress allows the technology to be an attractive solution to boost the well stream to overcome friction losses and maintain satisfactory production rates for longer distance tie-backs. There are many advantages of having gas compression such as: accelerating production and transporting, improve flow assurance. There are many real industries application for gas compression/boosting such as: Ormen Subsea Compression Station Pilot or Asgard Subsea CompressionThe technology of subsea gas compression seems new and just applied recently around 2010. However, the idea or fundamental concept can be traced back to 1985-1986 by engineers from Aker Solutions.

4.2. Challenges:The challenges or drive forces come up with the more discovery of wet gas field in over the world and the idea of not leaving this type of resource behind. However, there are still some challenges come up with the design for subsea gas compression: Design of compact and less weight in the seabed: as moved in deeper and deeper in the ocean, the size of subsea gas compression needed to be more and more compact. To do so, some components might be eliminated to reduce the size without reducing its performance and efficiency. The amount of weight has also need to be considered as hoisting the system also a challenge. Design of high reliability and little maintenance: when going subsea, it is not easy to access the equipment at the seabed compared to the situation onshore of on the FPSO. So the design of high reliability with little maintenance is crucial before the technology can be approved. The reliability of the system can be achieved by the simplicity of the design in subsea compared to the platform as more complex design tend to have higher risk of failure due to many parts or components. For maintenance, it is not feasible to hoist the large vessel system up to the surface just for maintenance. Therefore, components and sub-system have been packed in lighter modules which can be retrieved and handled easily.

4.3. Technology:There are two main approaches for designing gas compression: Multiphase gas compression subsea rotating machinery working directly on the well stream without preprocessing. For multiphase gas compressor, it has reduced system complexity, Internal cooling obtained by the liquid phase. However, efficiency will be reduced due to presence of liquid. In multiphase compressor designs, there are hydraulic design and additional process. The multiphase compressor operating conditions can be up to 90-100% GVF.Conventional design gas compression maximized dry gas compressor with upstream wellstream processing and associated control system. For conventional gas compression design, there have proven field experience and higher polytrophic efficiency.

Figure 15: Gas Compression Figure 3 Well stream compression

Figure 16: Gas Compression Figure 4 Conventional design gas compression

5. Decision making for components of subsea processing:A good engineering is to know how to make decision making based on parameter and scenarios on each situation. As our group is focusing on subsea processing, we would like to combine all of the available technologies as well as case scenarios to propose a general guideline how and what to choose the best component options based on available technology to develop subsea processing. The guideline is made by our own groups effort. However, due to many new and currently developing technologies, this guideline would need to be updated as the technology and the market demand evolves in the future.

5.1. Decision making parameters:As for this section, the designed parameters are listed as important factor to choose for each component:5.1.1. Selecting pumping design parameters:For pumping, there are key parameters for selection: Differential pressure needed to overcome hydrostatic and friction pressure loss during transportation Gas volume fraction or gas volume of tolerance of the pump. Particle/Solids size

Figure 17: Example of design parameter for pumps from INTECSEA5.1.2. Selecting separation design parameters:To design or selection separation, some key parameters should be considers: Flow rate of each fluid component: water, gas, oil and total liquid production Fluid characteristic: oil gravity, viscosity, etc. Operating conditions: operating temperature and pressure, designed pressure, etc. Number of phases needed to separate as well the main phase needed to be separated such as: gas from produced fluid or water from oil, etc. Other parameters such as: GOR, amount of space available, sand removals, etc.

5.2. Decision making scenarios:There are many different scenarios in offshore production. Each scenario will have each unique solution to match the best economy. In this section, we will go through many scenarios in the logical way with number of types of challenges increasing which can be faced while doing offshore and deeper water.5.2.1. Shallow water and short or medium tie-back distance: Pump: some types of pump should be used when encountering low reservoir pressure or low reservoir energy drive. A traditional multi-phase pump (ESP pump) due to low pressure loss with short tie-back distance which is usually vertical. With medium tie-back distance, other type of pumps could be considered to use as the larger differential pressure may be required Separation: the subsea separation system might not be installed with short tie-back distance due to the ability of multiphase pump. However, as long as there are some other special scenarios or other challenges needed to be addressed in the reservoir. If the reservoir experiences high water cut which usually happens in brownfield or marginal field, the consideration of subsea separation might be considered if the processing facility on shore has reach the maximum capacity. In this case, the subsea gravity based separation liquid-liquid (to separate water and oil) can be considered to use. Even though the subsea gravity based separation has a large vessel, the shallow water makes it possible to hoist and place it into the seabed Gas compression: at this point, mostly the job is to remove water and the produced fluid will be flow in one pipeline into the FPSO or onshore. So gas compression is not needed at this point of time.One example of the short distance configuration can be demonstrated below:

Figure 17: example of short distance con figuration5.2.2. Medium/deep water and medium/long tie-back distance: Pump: as we moved a little bit deeper into the ocean, the type of pump considered to use is based on several parameters and different challenges. The traditional multiphase pump cant be utilized due to the high pressure loss by hydrostatic pressure and frictional loss with the increase of tie-back distance. To transport oil, multiphase pump should be used instead of single phase pump even though single phase pump yield the highest pressure difference. The reason is that it cant handle the large gas volume as the gas might escape from the oil during transporting. Several type of pumps are the candidate such as: helico-axial pump, hybrid pump or twin-screw pump. The most popular choice is usually helico-axial pump which gives the reasonable high differential pressure and large volume of gas tolerance. Twin-screw pump and hybrid pump are considered better choice if we encounter Oligocene which is characterized with more viscous oil and low reservoir pressure. For water-injection: the water injection system could be installed at this time due to the in-efficiency of transporting water with produced fluid. At this point, centrifugal pump should be used to pump the water back to the reservoir to maintain the pressure. Separation: With the medium or deep water and medium tie-back distance, it is still reasonable to use gravity based separation which is gas-liquid separation. The reason to use gas-liquid separation is to reduce the duty of the pump and gas tolerance for the pump. So the main concept is to separate the gas from the produced fluid. It is mostly vertical, and takes quite amount of volume of space. However, compared to horizontal separator, vertical separator still take less space and still can be applied to a reasonable depth such as Pazflor at 800 meter depth. With the long tie-back distance, the subsea three phase separation should be considered as the important to separate any phase (oil, gas and water) is equal. So three phase gas separation seems the better choice Gas compression: As gas mostly will be separated in this type of situation, the gas compression might be required to transport the separate gas of line.Figure 18: Example of medium (on the left) and long (on the right) tie-back distance5.2.3. Ultra deep water and long tie-back distance:This type of situation is considered hypothetical situation in our project as some project or technologies have been under development and tested in onshore but not on the seabed yet. The main difference in here is the design of separation has to be changed as compact with high efficiency to go with the pump because of the efficiency of hoisting large vessels under deep water. Pump: mostly the same as deep water above Separation: new currently developed technologies needed to be considered to use in this situation. Some advanced technologies have been mentioned above to solve this problem such as: Caissor separator, inline separator or pipe segment separation. However, each of its still has limitation and need to be cautious to use with different challenges from deep sea water. Gas compression: mostly the same as deep water above.

6. Summary of works As shown above, subsea processing technology involve in many different aspects of technology in oil and gas industry. For the main purpose of this paper and to be the best fit with us as oil and gas engineering, we have eliminate the technology as power system, subsea controls, manifolds and pipeline system which are also a big improvement and importance in subsea processing system. We decide to focus on technology which is closely related to us such as: subsea pumping/boosting, subsea separation and subsea gas compression/boosting. We have reviewed the importance of subsea processing technology as well as go into each technology has been developed and used as: subsea pumping, separation and gas compression. As each technology has evolved in many years, different types of technologies for each component have been extensively developed. So it is impossible to go into details for each technology for each component. However, we still review the basic or fundamental concept for each component technology to understand its advantage as well as its own scenarios application After reviewing so many technologies, we try to combine the knowledge as a simple guide to choose what type of component technology based on parameters and scenarios challenges. All of these are based on real-life project after we have studied real life and understand the reason the company has developed this technology.

7. Future works for next semester. However, due to the large amount of work of different type of technologies involving with subsea processing, we havent able to cover the subsea gas compression which is also an important technology. It is quoted as the game changer for exploration and production in deep water. Besides, the other concept as water re-inject system might be considered as well a part of subsea processing system. Second, as the paper has given general review with many types of technologies, the lack of support by number or calculation is needed to strengthen our argument as engineers to decide to utilize subsea processing technology. Many places during the paper work have included more theories but not with practical number. As for our next term, we would love to address this issues with practical numbers used in industry. Thirdly, as we have given the general guides for engineering decision making to choose the component with many different type of scenarios in oil and gas industry. We would love to apply to real field which can be the candidate for applying subsea processing technology and citing as well as perform calculation which can help us to better understanding about the improved recovery when applying this technology Lastly, as any technology always has to gives a feasible economy to the project to be approved and applied in the industry. Many real life cases has gained the improvement in field economy by applying subsea processing techonology. It is important for us to perform a simple case study for the economy analysis to the improved economy of the field when applying the processing technology.

8. References:FMC Techonologies - http://www.fmctechnologies.com/Aker Solutions - http://www.akersolutions.com/One Subsea - https://www.onesubsea.com/Pagot, P. R., Werneck, M., Assayag, S., Cerqueira, M. B., & Herdeiro, M. A. N. (1996, January 1). Subsea Separation Systems. Offshore Technology Conference. doi:10.4043/8060-MSKhoi Vu, V., Fantoft, R., Shaw, C. K., & Gruehagen, H. (2009, January 1). Comparison Of Subsea Separation Systems. Offshore Technology Conference. doi:10.4043/20080-MSSeparations Technologies in Oil and Gas Production - http://www.diva-portal.org/smash/get/diva2:644207/FULLTEXT01.pdfSubsea Processing: A Holistic Approach to Marginal Field Developments. (2012, April 30). Offshore Technology Conference. doi:10.4043/22860-MSLima, F. S., Storstenvik, A., & Nyborg, K. (2011, January 1). Subsea Compression: A Game Changer. Offshore Technology Conference. doi:10.4043/22411-MSSulzer. (2003). Pump Handbook.

Bornemann, 2. (2013). Bornemann. Retrieved from Bornemann: http://www.bornemann.com/products/twin-screw-pumps/

E&P. (2013). Retrieved from E&P: http://www.epmag.com/Production/Electric-submersible-pumps-fine-tuned-gassy-wells_41014

Heyl, B. (2008). Multiphase Pumping. Texas A&M University.

Dustan Gilyard, E. B. (2010). The Development of Subsea Boosting Capabilities for Deepwater Perdido and BC-10 Assets.

Siqueira, A., Mendes, R. A., Furtado, C. J. A., Vieira, L., Furtado, C. J. A., Serra De Souza, A. L., Bezerra, M. C. M. (2012, April 30). Marlim 3-Phase Subsea Separation System (Petrobras): Introduction to the Involved Reservoir Background. Offshore Technology Conference. doi:10.4043/23228-MSS.Fenton, Subsea Production System Overview, Vetco Gray, Clarion Technical Conferences, Houston, 2008Subsea engineering handbook, Yong Bai and Qiang Bai, Gulf professional publishing , 2012Deepwater installation of subsea hardware, Stephen J Rowe, Brian Mackenzie, Richard Snell, Proceedings of the 10th Offshore Symposium, Houston, TX, Texas Section of the Society of Naval Architects and Marine Engineers (2011)Comparison study of deepwater installation methods, Simen Thorgersen, Masters Thesis, Faculty of Science and Technology, University of Stavenger (2014)R. Fantoft, Technology Qualification for the Tordis Subsea Separation, OTC 17981

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