Introduction to Subsea Processing

Introduction to Subsea Processing For new employees of the Asker Subsea Process Systems department

Rev. 04 Author: Lene Hæreid Henriksen Modified by: Marianne Winnes Steiner

Table of contents Abbreviation list.................................................................................................................. 5  1  Introduction ................................................................................................................. 6  1.1  FMC Kongsberg and the processing department ................................................. 7  1.1.1  History........................................................................................................... 7  1.1.2  The employees in the processing department ............................................... 7  1.2  Basic information ................................................................................................. 8  1.2.1  Basic terms .................................................................................................... 8  1.2.2  Hydrates ........................................................................................................ 9  1.3  What is processing? ............................................................................................ 10  1.4  Why subsea processing? (Drivers) ..................................................................... 11  1.5  Challenges subsea processing ............................................................................ 13  1.6  Subsea processing compared to topside ............................................................. 13  2  Studies and projects .................................................................................................. 14  2.1  Project phases from a customer’s point of view ................................................ 14  2.1.1  Study phase ................................................................................................. 14  2.1.2  Project phase ............................................................................................... 15  2.2  Studies, tenders and projects in FMC................................................................. 16  2.3  Delivery Projects ................................................................................................ 17  2.4  Important studies and projects in FMC’s subsea processing history ................. 17  3  System design ........................................................................................................... 18  3.1  Design basis........................................................................................................ 18  3.2  Codes and standards ........................................................................................... 18  3.3  Field architecture ................................................................................................ 19  3.4  Process................................................................................................................ 21  3.4.1  Bulk water separation, reinjection of water and pumping. ......................... 24  3.4.2  Gas/liquid separation and pumping of liquid (similar to the Pazflor system). 24  3.4.3  Bulk water separation, sand-handling, re-injection of water and pumping. 25  3.4.4  Gas/liquid separation, compression and pumping. ..................................... 26  3.4.5  Bulk water separation, sand handling, re-injection of water, gas/liquid separation, compression and pumping. ..................................................................... 27  3.4.6  Hydrates and system design ........................................................................ 28  3.4.7  Schematics and diagrams ............................................................................ 29  3.5  Control system.................................................................................................... 31  3.5.1  Components ................................................................................................ 32  3.5.2  Redundancy................................................................................................. 33  3.5.3  SCD (System Control Diagram) ................................................................. 33  3.6  Power system...................................................................................................... 35  3.6.1  Single line diagram and load list................................................................. 37  3.6.2  Calculations and analysis ............................................................................ 38  3.7  Modules .............................................................................................................. 39  3.7.1  Retrievability............................................................................................... 39  3.7.2  Modules....................................................................................................... 39  3.7.3  Module weights, ship accessibility ............................................................. 39  3.7.4  Wire weight................................................................................................. 39  2

3.8  3D construction .................................................................................................. 41  3.9  Technology gap .................................................................................................. 42  3.10  Cost estimation ............................................................................................... 42  4  Products..................................................................................................................... 44  4.1  Separators ........................................................................................................... 44  4.1.1  Liquid/liquid separation .............................................................................. 44  4.1.2  Gas/liquid separation .................................................................................. 50  4.1.3  Sand handling.............................................................................................. 53  4.2  Pumps ................................................................................................................. 56  4.2.1  Single Phase centrifugal.............................................................................. 57  4.2.2  Multiphase helico axial ............................................................................... 58  4.2.3  Hybrid pump ............................................................................................... 59  4.2.4  Multiphase twin screw ................................................................................ 60  4.2.5  Submersible pumps ..................................................................................... 61  4.3  Compressors ....................................................................................................... 62  4.4  Coolers ............................................................................................................... 64  4.4.1  Coolers in a compression system ................................................................ 65  4.4.2  Natural convection pipe cooler ................................................................... 67  4.4.3  Forced convection pipe cooler .................................................................... 68  4.4.4  Shell and tube cooler ................................................................................... 69  4.5  Valves ................................................................................................................. 70  4.5.1  Control valves ............................................................................................. 71  4.5.2  Choke valve ................................................................................................ 72  4.5.3  Check valves ............................................................................................... 72  4.5.4  On/off valves............................................................................................... 73  4.6  Electrical equipment ........................................................................................... 75  4.6.1  Actuators ..................................................................................................... 75  4.6.2  Transformer................................................................................................. 76  4.6.3  Switches ...................................................................................................... 76  4.6.4  VSD (Variable Speed Drive) ...................................................................... 76  4.6.5  Cable ........................................................................................................... 77  4.6.6  Connectors .................................................................................................. 78  4.6.7  Penetrators................................................................................................... 79  4.7  Instruments ......................................................................................................... 79  4.7.1  Pressure and temperature transmitters ........................................................ 80  4.7.2  Level transmitter (LT)................................................................................. 80  4.7.3  Radar ........................................................................................................... 81  4.7.4  Oil in water measurements.......................................................................... 82  4.7.5  Watercut transmitter.................................................................................... 83  4.7.6  Flow transmitters ........................................................................................ 83  4.7.7  Leakage transmitters ................................................................................... 84  4.8  Intervention ........................................................................................................ 85  4.8.1  Connectors .................................................................................................. 85  4.8.2  Connection methods.................................................................................... 86  4.8.3  Tie-in/connection tools ............................................................................... 87  4.9  Structure ............................................................................................................. 89  3

4.9.1  Foundations ................................................................................................. 90  4.9.2  Protection .................................................................................................... 91  5  Design and dimensioning.......................................................................................... 92  5.1  Separator tanks ................................................................................................... 92  5.2  Pumps ................................................................................................................. 93  5.3  Compressors ....................................................................................................... 94  5.4  Coolers ............................................................................................................... 94  5.5  Valves ................................................................................................................. 95  5.6  Electro system .................................................................................................... 96  5.6.1  Transfer voltage .......................................................................................... 96  5.6.2  Transformers ............................................................................................... 96  5.6.3  Cable dimension and construction .............................................................. 96  5.6.4  Penetrators and connectors ......................................................................... 97  5.6.5  VSD (Variable Speed Drive) ...................................................................... 97  6  Technology qualification .......................................................................................... 98  6.1  Analytical qualification and testing.................................................................... 99  7  Testing..................................................................................................................... 100  7.1  Tests ................................................................................................................. 100  7.2  Testplanning ..................................................................................................... 101  7.3  Test plan ........................................................................................................... 102  8  List of figures .......................................................................................................... 103 

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Abbreviation list Abbreviation CT EFAT FAT FEED GVF HLL HPT HTT LLL LT MC MEL PDO PT PT SCM SCU SIT SOT SPCU SPS ST SWT TQP TT VSD

Description Commissioning Test Extended Factory Acceptance Test Factory Acceptance Test Front End Engineering and Design Gas Volume Fraction High Liquid Level High Pressure Transmitter High Temperature Transmitter Low Liquid Level Level Transmitter Mechanical Completion Master Equipment List Plan for Development & Operation Performance Test Pressure Transmitter Subsea Control Module Subsea Control Unit Site Integration Test Site Operation Test Subsea Power and Communication Unit Subsea Process Systems String Test Shallow Water Test Technology Qualification Program Temperature Transmitter Variable Speed Drive

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1 Introduction This booklet is an introduction to the Subsea Process Systems (SPS) department, its history, our products and studies & projects. Together with exercises this booklet is an obligatory course for all new employees of the department.

Figure 1-1 FMC Globally

In Figure 1-1 there is an overview of FMC’s offices worldwide, and in Figure 1-2 there is an overview of FMC subsea worldwide. Which office that deals with which project will depend on where the client (i.e. the oil company) is located and project type. Kongsberg is the main office in Norway and the home of most departments related to subsea production. The processing department in Asker executes studies and projects for the European oil companies, and because we are center of excellence on subsea processing we assist other offices with processing projects. Other offices in Norway: - Kristiansund: Customer support and personnel for assistance with intervention. - Bergen: Training centre, customer support and personnel for assistance with intervention. - Stavanger: Field development and MPM (Multiphase Meter).

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Figure 1-2 FMC Subsea globally

1.1 FMC Kongsberg and the processing department 1.1.1 History 1974: Oil division established by Kongsberg Våpenfabrikk 1986: Kongsberg Offshore AS established 1987: Sold to Siemens 1993: Sold to FMC 2001: Changed our name to FMC Kongsberg Subsea AS In the oil and gas business it is important to be pro-active, it is crucial to know what will be the technology needed in the future (in 10-20 years time). In 1999 Kongsberg Offshore established a department in Asker where studies on subsea processing were to be performed. This started with two employees who had several years of experience from Kongsberg Offshore and in collaboration with the big oil companies they explored the new technology (phase1). The studies gained a lot of attention and the activity went on to include product development (phase 2). New employees were added to the workforce and the activity increased. In summer 2005 the department had a breakthrough with the award of the Tordis SSBI (Subsea separation and injection) (phase 3). Since then the department have grown in amount of employees and number of studies and projects. 1.1.2 The employees in the processing department We are a young and dynamic department with great capacity and an exciting future. Competence is highly appreciated in our department and competence development is a highly prioritized activity. We appreciate social interaction to solve a task. That implies an open informal way of communicating and collaboration between all types of employees. In this department we are all equal and we respect each other independent of position. The hierarchy is only visible on paper and when important decisions are to be made. 7

As a new employee it is important to take initiative and to be independent. We have an “open door culture” and if you ask you will receive help. We are always glad to share our competence. It is important to be sociable in other ways than in a job situation. The coffee bar, which is a social meeting place, and different sports activities are parts of our daily teambuilding.

1.2 Basic information A reservoir is a subsurface pool of hydrocarbons contained in porous rock formations which originates from sedimentation of organic matter. The hydrocarbons are trapped by overlying impermeable rock formation barriers. There are not only oil and gas present in a reservoir. When producing from a reservoir water and sand are also present and foam and emulsions may occur and needs to be handled in a process system; subsea or onshore.

Figure 1-3 Left: Reservoir Right: Phase layers

1.2.1 Basic terms •

Viscosity Viscosity is a measure of a fluid's resistance to flow. It describes the internal friction of a moving fluid. The higher viscosity, the more energy is required to extract the oil from the pores in the reservoir. Oil has a higher viscosity than water.

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Figure 1-4 Oil with high viscosity

•

Emulsion In an emulsion, one liquid (the dispersed phase) is dispersed in the other (the continuous phase). Challenge to separate.

Figure 1-5 Left: Water in oil emulsion. Right: Oil in water emulsion

•

Foam Foam is a substance that is formed by trapping pockets of gas in a liquid

1.2.2 Hydrates Hydrate is a substance similar to ice that can block a pipe, decrease the pipe diameter or form lumps in the liquid phase that will gather in valves or in other obstacles. It is formed by free water and HC gas under high pressure and low temperature. Formation of hydrates can slow down the production or lead to long shut-down. Removing hydrates leads to costly production losses and are time and resource consuming operations. Removal of hydrate plugs is a risk and has led to fatal accidents. The plug can exit the pipe like a bullet. Attempts to melt a hydrate plug in a pipeline with heat from the outside can cause the pipe to explode.

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Figure 1-6 Removal of hydrate plug

1.3 What is processing? Processing is active treatment of fluids. Subsea processing involves:  Separation – to separate different fluids, liquid from liquid, gas from liquid  Cooling – of fluids and motors  Filtering – to separate particles from fluids  Pumping – of single or multiphase  Reinjection – reinjection of fluids and solids into a reservoir  Compression – compression of gas  Dehydration – separation of liquids from gas  Injection of chemicals – MEG, methanol and emulsion breakers, to give the fluids a specific ability

Figure 1-7 Our part of a system

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In Figure 1-7 we see examples of different subsea systems. Fluids are extracted from the reservoir through the xmas tree (blue ring), flowlines from the wells are gathered in a manifold (green ring) and brought to the processing system (red ring). The fluids are processed and then transported topside (platform, ship or shore).

1.4 Why subsea processing? (Drivers) 1. Reduced CAPEX (Capital expenditure compared to building a platform)

Figure 1-8 How the cost of a project can be divided into different phases.

CAPEX OPEX MAINTEX DISPEX

Capital Expenditure Operational Expenditure Maintenance Expenditure Disposal Expenditure

2. Expand production in existing fields where the pressure has decreased in the reservoir. Meaning fields where cost efficient production is no longer possible with standard production equipment. 3. Makes it possible to exploit costly infrastructure fully throughout the systems operational period. Capex and production costs will be reduced when you can extract more from each field and produce more efficiently. 4. Accelerate production with removal of bulk water or boosting. Bulk water removal will avoid produced water to congest pipelines or topsides, free up capacity to allow increased oil production and provide less ’head’ in risers / flowlines (deepwater). Boosting gives the opportunity to lower the wellhead 11

5. 6.

7. 8. 9.

pressure with a choke and then pump the fluids further through the system. This way more oil and gas can be extracted from the reservoir. Enhances flow management by decreasing slugging and avoid forming of hydrates. Makes it possible to depressurize the system as a hydrate strategy. In a system where the gas rises freely to the surface and the liquids are boosted with pumps, it is possible to vent the system to depressurize it in case of a shut down. The pressure will fall to approximately 1 atm and hydrates will not be formed. Makes it possible to exploit fields that are normally inaccessible because of deep water or long step out. Boosting makes the fluids able to travel longer distances. Makes it possible to connect satellite fields to existing infrastructure. It is easy to adjust system to future changes. HSE: - The platforms influence on the environment and vice versa will decrease dramatically. Disposal of produced water, waste from platform, flaring etc. will be reduced.. The equipment will not suffer from environmental impact such as hurricanes or icebergs. - Decrease danger of kidnapping, personal injury or error because there is no need for personnel on a platform and the system mostly controls itself. - Decrease possibility to sabotage the system which is a threat in e.g. Nigeria. Examples of sabotage can be fire, bad management, lack of maintenance, shut downs and corruption.

Figure 1-9 Troll A platform and corresponding subsea solution

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1.5 Challenges subsea processing     

High pressure, deep water The components have to stand on the seabed for at least 5 years without maintenance It is expensive and technically demanding to install/intervent on subsea components on great depths Need to have the complete overview and control of process on great depths Materials must cope with harsh subsea environment

1.6 Subsea processing compared to topside Why can’t we use the same equipment subsea as topside?  The demand for operating time without maintenance is a lot higher. This leads to less ancillary systems, simplified solutions and more robust components.  High external water pressure  External water phase is especially demanding for electric components  Higher design pressure because of demands for design for shut-in pressure subsea while systems topside are designed with a security system  Higher design temperature because the system is located closer to the reservoir Separation subsea compared to topside:  coarser separation  simpler separation tanks  less control (simplified system)  more robust equipment.

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2 Studies and projects This chapter will address how studies and projects are performed from the clients as well as FMC’s perspective.

2.1 Project phases from a customer’s point of view

Figure 2-1 The projects phases from a customers point of view

The project phases depend on client and project. What should be remembered is that a project is divided in a study phase (consisting of different stages) and a project phase. These two main phases are divided by a PDO (plan for operation and development) and selection of suppliers. The figure used is based on Hydro’s project handbook. 2.1.1 Study phase This phase is characterized by seeking to expand the scope with as many solutions as possible to have a lot to choose from and then decrease the scope by excluding solutions until left with one (and possible fallback solutions). The feasibility study is divided into two phases, during the first phase the client investigates if it is feasible to develop the field: a +-40% estimate for operation. If they find it feasible to develop the field they contact contractors (system suppliers: FMC, Aker, Vetco) to discuss solutions and find alternative ways to proceed. In the concept study phase relevant concepts are studied and one needs to end up with one or several concepts to investigate further in the FEED (Front End Engineering and Design) study. The same study is often performed by several system suppliers at the same time and many studies (on different subjects, for instance a study of the electro system can be done at the same time as a study on the process system) are done in parallel. In FEED studies design and costs are investigated more thoroughly. FEED is done in different ways; it can be done by all qualified suppliers or a selection of these. In the case 14

with several suppliers the oil company will choose to keep all information to itself or the best solutions from all suppliers are combined to make an inquiry. In the case where there is only one supplier doing the FEED, all bidders are let in on the solutions, so this must be considered when writing the report. How much information must be given to get the job without giving away good ideas to the competitors? After FEED the oil companies send an inquiry to the suppliers they want a tender from and then choose a supplier (usually without telling the selected company). The next task for the oil company is to make a PDO (Plan for Development & Operation) which is an overview of the entire project: investment, lifetime, production, impact on environment etc. This is sent to Stortinget (the government) for approval before the project can proceed. The need to send in an PDO will depend on the size of the project, if the investment is under 1.5 billion NOK it is not necessary to send in a PDO. System suppliers are now informed. 2.1.2 Project phase The next phase consists of detail engineering and procurement. This is where most of the work is performed. The chosen idea is improved and all details come into place. Now the system can be built, after this follows start-up, production, support and maintenance. In some cases the plant will be modified as it ages, and depending of the cost a new PDO will have to be approved. Tordis SSBI Project phases:        

Design competition; June 2004 (Vetco, AKS, FMC) FEED studies; September 2004- July 2005 (AKS, FMC) Technology Qualification; November 2004-2006 (AKS, FMC) Tender, spring 2005 (AKS, FMC) Pre engineering study; July 2005 – October 2005 (FMC) Letter of Intent with EPC option; July 2005 (FMC) Project sanction October 2005 Project execution 2005-2007

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2.2 Studies, tenders and projects in FMC Studies and tenders are carried out by the Field Development group and System Engineering in Asker. These groups carry out most of the work together with the product and the marketing group. If the study/offer contains standard equipment and process equipment the work is carried out by the departments involved in collaboration with the Subsea Process Systems (SPS) department in Asker. If the study/tender only contains process equipment the work is carried out by the SPS department. The Field Development group/System Engineering handle all the technical details as well as working out how FMC’s products can be combined to create a good system. In addition they determine if there are any components lacking that need to be developed. The departments are in direct contact with the client and arrange studies and tenders. The goal of the Field Development group/System Engineering is to obtain studies and projects for the company. Studies are normally paid by the client, but in some cases FMC do the work without getting financed. This is done to be able to come up with good ideas and solutions in an early phase of the project. In this way we promote ourselves and will have a possibility to influence on the customer’s choices. Several studies can be done on the same project, and it does not always result in a contract. The goal is to obtain 40% of the contracts we tender for. A certain strategy is needed to win a contract. There are more aspects to consider than having the best technical solution and lowest price, i.e. contract issues and our relation to the customer. The client and FMC may work together for up to 20 years, and a good cooperation is essential. Cultural differences and laws have to be taken into account when working with foreign companies. Local suppliers and service stations may be wanted from the customer. This implies that one does not always choose the cheapest and simplest solution but the solution the customer wants. Projects are carried out by the project department, so if we get a job a project group is assembled and the project department will lead the work. The first step is detail engineering. This is where most of the work is done. All details are worked out, ordering and testing and at last the system is put together. Construction and detail engineering intertwine. After system delivery and start-up FMC’s role is to do support, but the merchandise is delivered and belongs to the client. If the system is to be changed after a few years, FMC will participate. More details about projects will be discussed in the delivery project chapter.

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2.3 Delivery Projects When starting up a delivery project a project organization is established with focus on engineering, delivery and testing. Process engineering is in charge of process design (including process control system) and technical follow-up of subcontractors delivering processing equipment. The project’s Work Package manager is responsible for processing equipment, writes contracts with subcontractors in collaboration with purchasing/contracts, and has the overall responsibility for deliveries. This implies collaboration with engineering, test, HSE, QA/QC, material, logistics, contracts and purchasing. Product documentation is especially important for the subsea processing projects because we have limited experience. We need good descriptions of products and specifications in relation to subcontractors and for use in future projects/studies.

2.4 Important studies and projects in FMC’s subsea processing history On the department’s Share Point on the intranet a reference list with studies and projects can be found. Not all studies have led to projects, but have been a good experience in finding system solutions and developing equipment for separation and compression. The list is found on: http://inside.ask1.net.fmcti.com/products/subsea/process_system/Lists/Projects/AllItems. aspx

Figure 2-2 Reference list of studies and projects

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3 System design This chapter addresses how to proceed and what to consider when designing a processing system.

3.1 Design basis Design basis shows the purpose of a process design. It contains information and demands given by the client to FMC for delivery of a study, tender or project. Conditions like depths, temperatures, currents, fluid composition (water, MEG, CO2, H2S, sand, slugging) and design pressure is given, and information about expected production rates, start up/shut-down and hydrate-philosophy. Expected availability is information important for planning. It is given as how many percent of the systems lifetime the client expects the system to be available, i.e. working. This will depend on the failure rates of the components and redundancy choices. Design basis is updated for every step in the work process (when there are changes) as the client decides which solution they want or which solutions to study further. Details of the concept (separation (type), re-injection, compression) is not decided in the early phase therefore we have the opportunity to make suggestions. However in the later phases, as the FEED phase, the choice is made and FMC has to study the concept choice the client has made. Based on the design basis from the client, FMC makes its own with more information and incorporate our own demands. This is sometimes sent to the client for approval. This is a method used to clear up uncertainties concerning the specifications given by the client.

3.2 Codes and standards Codes and standards are instructions on how systems and components have to be designed and dimensioned. Below are some examples of standards used:           

API ASME BS DNV EN IEC IEEE ISO NACE NORSOK NS

American Petroleum Institute American Society of Mechanical Engineers British Standard Det Norske Veritas Europeisk Norm International Electro technical Commission Institute of Electrical & Electronics Engineers The International Organization of Standardization National Association of Corrosion Engineers Norsk Sokkels Konkurranseposisjon Norsk Standard

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There are standards for how to draw a diagram and with a given design pressure the standards gives specifications of the equipment to be used. Each area of expertise has its own standards. Independent organizations create the standards, and some of the standards overlap each other. The client decides which standards to use, and the system design depends upon their choice of standard.

3.3 Field architecture

Figure 3-1 Example of field architecture

When construction of a system is planned where to place the modules has to be considered. Evaluation of where to place the wells and xmas trees has to be done first. Then it is decided where to lay the flowlines and how to gather them in a manifold without causing too much slugging and pressure/temperature loss. The process unit is placed according to the production equipment. When modules and flowlines are placed, umbilical, communication – and power lines are placed according to the rest. The client decides where to place the different units, but FMC’s Field Development department may help in the planning.

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Depths, soil, landscape and distances (between modules and modules and topside) will influence the planning of field architecture and infrastructure. Mooring for ships and platforms will also influence the location of modules.

AVSTAND TIL MOTTAK [km] Stepout (km) 0

20

40

60

80

100

120

140

160

180

Corrib (gas)

500

Snøhvit (gas)

Popeye (gas) Pluto (gas)

VANNDYP [m]

Depth (m)

1000

Gemini Ormen Lange (gas)

Nile (gas)

1500

Mica (oil) Mensa (gas)

Diana (gas)

2000

Thunder Horse (oil)

Canyon Express (oil)

2500

Na Kika (oil)

3000

Figure 3-2 Depths and step-out for existing developments

Today we operate in depths between 150 and 3000 m and step-outs of 0 to 200 km. We see from Figure 3-2 that developments on the ocean floor have gone from deep to ultra-deep waters with increasing step-out. The easy accessible areas have already been exploited, but the need for energy still increases. One is forced to operate in deeper waters longer distances from shore. This application requires new equipment to make production possible/profitable. (Deep fields: Gulf of Mexico, Long step-out: Shtokman)

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3.4 Process

1

2

3

4

5

Figure 3-3 Development subsea processing

When it comes to development and solutions one must take into account that the oil and gas industry is conservative and the ideas for subsea separation and compression developed long before the equipment. Look at Figure 3-3 to get an overview of what is done and our goals for the future. 1. Multiphase boosting – Pumping of multiphase flow 2. Bulk water removal (Troll pilot and Tordis) – Removal of produced water from multiphase stream and injection into reservoir 3. Gas/liquid separation, desanding – Gas and liquid is separated and sand is removed from the separator through a separate system 4. Gas compression (Ormen Lange and Åsgard with gas/liquid separation and gas compression) 5. 3 phase separation, desanding, reinjection and compression. Water and sand is removed from the wellstream and re-injected into a reservoir, gas and liquid is separated and the gas is compressed. Note that the need for separation and boosting is different from one field to another, and that the goal is to have the opportunity to utilize the technology mentioned even though it will not always be necessary. There are many ways to assemble a process system so there is no correct solution. The system design is studied and found in cooperation with the client. The solution will depend on the types of fluids found in the reservoir (what does the customer want to separate), need for boosting and what the customer has done before and wants to do now. FMC will try to get the customer to implement subsea processing which is easier the earlier we are invited to do studies in a project.

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Figure 3-4 The Tordis SSBI station

The main functions of the processing system are pumping, separation, compression and cooling. From Figure 3-5 we can see examples of a pump for boosting and re-injection, separators for separation of fluids, compressor which compresses the gas and coolers which cools fluids and motors. These components can be combined in different ways to give the desired results.

Figure 3-5 The main components of the processing system

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Figure 3-6 Processing alternatives

Figure 3-6 shows some processing alternatives: 1. Bulk water removal, reinjection of water and pumping 2. Gas/liquid separation and liquid pumping. 3. Bulk water separation, sandhandling , reinjection of water and pumping. 4. Gas/liquid separation, compression and pumping. 5. Bulk water separation, sandhandling (with injection into reservoir or into oil/gas pipe), reinjection of water gas/liquid separation, compression and pumping. Except for alternative 5, the systems in Figure 3-6 are systems proposed in studies and tenders. This is a simplified summary and not a method on how to build a processing system. Every field and study/project demands a special solution to obtain optimal production. The separators shown here are examples of liquid/liquid and gas/liquid separators, there are other types of separators which perform the same tasks, these will be presented in chapter 4.1. In the following sections we will look at the different processing alternatives.

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3.4.1 Bulk water separation, reinjection of water and pumping.

Figure 3-7 Bulk water separation, reinjection of water and pumping

The bulk water is separated in a gravitational separator and re-injected into a reservoir with a reinjection pump. The reason for this is to avoid using energy and capacity on bringing the water to the surface. Oil, gas and potential sand is pumped with a multiphase pump topside. This can be relevant for fluid compositions with high water levels and low gas levels. 3.4.2 Gas/liquid separation and pumping of liquid (similar to the Pazflor system).

Figure 3-8 Gas/liquid separation and pumping of liquid

The gas and liquid is separated and the gas rises to the surface in a separate pipe while the liquids and potential sand is pumped topside with a multiphase pump. This solution gives the opportunity to depressurize the system in case of a shut-down to avoid forming of hydrates. This can be relevant for fluid compositions with high gas levels and low water levels where the fluids are to be transported short distances to platform or to shore. 24

3.4.3 Bulk water separation, sand-handling, re-injection of water and pumping.

Figure 3-9 Bulk water separation, sand-handling, re-injection of water and pumping

This is a simplified version of the solution used for the Tordis project. The solution is similar to the one in alternative 1, but in this case sand-handling is used. There will always be sand in the flow from the reservoir, and it will accumulate in the separator. Depending on the amount, a desander may be necessary to obtain optimal separation and to avoid clogging. In addition, separating sand protects the pumps from sand erosion causing them to fail and therefore requiring replacement. From the first separator sand is flushed into a sand tank, water is separated from the sand and injected into the water re-injection pipe upstream the re-injection pump. The sand is flushed to the water re-injection line downstream the water re-injection pump (Alt. 1 Figure 3-9) or into the gas/oil flowline downstream the multiphase pump (Alt.2 Figure 3-9).The first alternative gets rid of the sand, and there will be no need to occupy capacity or time bringing sand to the surface and separating it for a second time. On some occasions it will not be possible to re-inject sand into a reservoir (depending on the reservoir content and form), or it will not be economically beneficial. In this case the second alternative is chosen. The benefits of this solution are that the sand is removed from the bulk water removal separator and that the pumps are protected when sand is injected downstream the pumps in the system. This separation process can be relevant for fluid compositions with high water and sand levels and low gas levels.

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Figure 3-10 The Tordis processing system

3.4.4 Gas/liquid separation, compression and pumping.

Figure 3-11 Gas/liquid separation, compression and pumping.

In this process system gas and liquid is separated. The liquid (and sand) is pumped through a multiphase pump while the gas is boosted with a compressor. Gas and liquid can then be exported to platform/shore separately (Alt. 1 Figure 3-11) or in the same flowline (Alt.2 Figure 3-11). Transportation in the same flowline is cheaper and the gas will contribute to the transport of the liquid, but gas and liquid will have to be separated again at topside location. Transportation in two pipes is more expensive, but further separation of the fluids is avoided. A problem with the two pipe solution is that hydrates (slush-like substance formed by water and gas) may be formed in the gas riser as temperature falls because MEG (anti-freeze chemical) follows the liquid phase. There are three main places a cooler is needed. Three coolers will not be used in the same system because they occupy too much space, so the coolers shown in Figure 3-11 are just 26

to display the possibilities. Inlet cooling, anti-surge cooling and outlet cooling is shown in the drawing. Inlet cooling is done to remove liquid from the gas (liquid drops will ruin the compressor) and to obtain a temperature that will improve the compressor efficiency. Anti-surge recirculation loop is activated at low flow/high pressure in the system. The recirculated gas is hot and has to be cooled before re-entering the compressor in order to maintain compressor performance, hence the anti-surge cooler. Outlet cooling is needed because the flowlines are not designed for the high temperature of the gas at the outlet of the compressor. A cooler has often more than one purpose, i.e. one cooler may be a combined anti-surge and outlet cooler. Coolers will be discussed further in the chapter 4.4. This separation process can be relevant for fluid compositions with high gas and low liquid levels where the fluids are to be transported over long distances. 3.4.5 Bulk water separation, sand handling, re-injection of water, gas/liquid separation, compression and pumping.

Figure 3-12 Bulk water separation, sand handling, re-injection of water, gas/liquid separation, compression and pumping.

This is similar to a topside system and is what will be possible subsea in the future. Water and sand are separated from oil and gas and will be treated as in alternative 3. Then gas and oil will be separated in a gas/liquid separator and the gas is boosted with a compressor while the oil is pumped. The two fluids are transported in separate pipes or in a combined pipe topside. A cooling system like the one described in alternative 4 is needed. This separation process can be relevant for fluid compositions with high water and sand levels where the oil and gas will be exported over long distances.

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3.4.6 Hydrates and system design Hydrate philosophy, a philosophy on how to avoid hydrates, is an important part of system design. There are different modes in regards to hydrate formation: normal, nonnormal, shut-down and removal of hydrate plug. Throughout studies and projects you plan how to build the system so that hydrates will not be formed, what to do if hydrates do form, what to do at system shut-downs and how to remove hydrate plugs/layers if these are formed. It is not always possible to operate outside the pressure and temperature conditions where hydrates form. At the inlet of the compressor low temperatures are needed and in long flowlines the temperature will decrease with distance, and actions to avoid hydrates have to be taken. To prevent the temperature from falling to a level where hydrates will form it is possible to insulate flowlines (but this will be cost inefficient and will have little effect on flowlines longer than 15-20 km) or components or heat them from the outside. MEG (Mono Ethylene Glycol) and methanol work as de-froster liquids. To avoid hydrates MEG or methanol can be injected into the liquid (this is known as inhibiting the fluid) and will act as a de-froster in the liquid phase. Problems will occur when the system has to be shut down or if there is a gas phase which is cooled and water condenses (in the anti-surge cooler). In this case water can react with the gas and form hydrates. MEG or methanol can be injected upstream coolers to melt hydrate plugs in the pipes, on top of vertical gas/liquid separator to melt hydrates in demister, in the pipe between separator and compressor to inhibit condensed water from the gas at shut-down and in the outlet pipe of the compressor to inhibit condensed water. Chemicals have to be removed from the fluids topside. MEG can be regenerated and used again but methanol is not costeffective to regenerate. Part of the injected methanol is lost to the gas phase and can pollute the gas decreasing its market value.

Figure 3-13 Hydrate curve for wellstream. From Tordis.

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Figure 3-13 is an example from Tordis of a hydrate curve for a wellstream with and without MEG in the water phase. Every fluid composition will have a separate hydrate curve, but generally hydrates will form at low temperature and high pressure. From the figure it is seen that the possible area of operation will increase dramatically when inhibiting the water. The operational pressure on Tordis is 25-40 bar. Without MEG injection the temperature can be lowered to approximately 15 °C and with 50 % MEG in the water to about -7 °C before hydrates will form. If the system is shut down the temperature will start to decrease and to avoid hydrates in this situation the pressure should be lowered by for example depressurization to the surface, as planned for Pazflor. 3.4.7 Schematics and diagrams When designing a process system different diagrams are used to get an overview of the process. We will look at PS (Process Schematics), PFD (Process Flow Diagram) and P&ID (Piping & Instrument Diagram). PS is only made for subsea systems while PFD and P&ID are made for both topside and subsea systems.

Figure 3-14 Process Schematics for the Tordis processing system

PS (Process Schematics), see Figure 3-14, shows how the components should be placed in reference to each other (where the pump should be placed in reference to the separator, 29

in which direction the pipes will go). It is customary to make one PS for each retrievable module.

Figure 3-15 Process Flow Diagram for the Tordis processing system

PFD (Process Flow Diagram), see Figure 3-15, is made for a simple overview of the process. It shows the main flow and components, main control loops, pressure, temperature and rates.

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Figure 3-16 P&ID for Tordis

P&ID (Piping & Instrument Diagram), see Figure 3-16, shows the system in detail, all piping and instruments, line number, tag number and insulation (lines and equipment).

3.5 Control system The control system supplies all the units of the subsea separation system (SSS) with power, hydraulics and MEG through receiving information, process the information and give orders. The control system is designed and constructed by control systems in Kongsberg but the Asker office is responsible for control philosophy for the process control system.

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Figure 3-17 The main elements of the control system (for the production system).

3.5.1 Components The control system consists of the main components SCU (Subsea Control Unit), SPCU (Subsea Power and Communication Unit) and SCM (Subsea Control Module). The SCU is the master and the SCM the slave, the SPCU is the link between these two.

HPU

SCU

Operator Station

SPCU

Smart T ool

T EM A T EM B Elektris k kabel F iberoptis k kabel

SCM S E M A

S E M B

SCM S E M A

S E M B

SCM S E M A

S E M B

Figure 3-18 Main elements of the control system. Artistic view (left) and diagram (right).

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Underneath are more thorough descriptions of the control systems components: 



   

SCM – Subsea control module – gathers values from all sensors and valves, passes the info on to SPCU, executes orders from SCU (through SPCU), contains internal sensors and controls, is the boss subsea but makes no decisions on its own, act on orders from SCU through SPCU. SEMA/B are computers and the subordinates of SCM. They are equal and have separate el and communication systems so that SEMB can fill in for SEMA in case of a defect on SEMA and its system. The line between SEMA and B is checked every minute. SPCU- subsea power and communication unit – exchange information between SCU and SCM, works as a connecting link and translator. TEMA/B are the computers and subordinates of SPCU, they are equal and have, as for SEMA/B, separate el and communication systems so that TEMB can fill in for TEMA in case of defect on TEMA. Smart tool – remote control tool that can be connected to SPCU for configuration on SPCU. HPU – Hydraulic power unit- system of hydraulic pumps and reservoirs that supply the subsea system with hydraulic pressure. Run by electric pumps, gives LP and HP, monitored by SCU. SCU- subsea control unit – receives information and process it, gives orders on action, is the head of the control system. SCU communicate with the operator stations where the system can be monitored and controlled. There are two options for communication cables: electric and fiberoptic cables. Redundancy is obtained by sending all signals through the two systems.

3.5.2 Redundancy The control system is designed with double components and functions to secure reliability and availability. It mainly consists of an A and B system with redundant power supply and redundant communication lines. The SPCU has two computers: TEMA/B, the same yields for SCM which has SEMA/B. All pressure and temperature transmitter are double and sends information to both the A and B system. 3.5.3 SCD (System Control Diagram) Figure 3-19 shows a SCD. This is a diagram based on P&ID which visualizes and describes controlling, logics, operational interface, interlocking and shut-down of a processing system. This works as a basis for the control system. (Asker makes SCD and Kongsberg does the programming).

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Figure 3-19 SCD for Tordis process control system. From the P&ID this diagram which is the base for the control system is made.

Examples on what has to be controlled in the processing system: Level control of the separator is done by controlling the pump speed. The regulator will decrease the pump speed when the level is below a given point (LLL) and increase the speed when the level exceeds a given point (HLL). Minimum flow through the pumps is ensured by a loop with valves (min. flow loop). Min. flow valves are controlled by use of flow transmitters downstream the pump. Orders are to open on low flow to the pumps and close when flow reaches a certain point.

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Figure 3-20 Fraction of the SCD, function template.

The red square in Figure 3-20 is called a function template and is the building stone of the SCD. It represents the control function:     

Function tag is the ID and number of the function template, in this case a level transmitter, LT. Typical (internal control option/ variant for specific template) System & unit in control system (SAS) – which unit controls the function template Function template – Type of monitoring and presentation of data. MA: Monitoring of Analogue process variables Text field – optional, dedicated for additional information to the reader of the SCD

3.6 Power system Power is to be delivered to processing and control equipment. The customer has (usually) not specified a solution but has given information about depths, power source and distance from power source to subsea system. Planning is done according to the placing and the power need of units and control system over a period of time. Where all the components will be located has to be know and how much power they need before starting to plan the electro system. Since the system will change with time (the need for boosting will increase with the age of the field) the need for power will vary (see Figure 3-21). When producing from the reservoir the pressure will fall and the need for

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boosting, pumping or compression, will present itself. The reservoir pressure will continue to decrease and the boosting must counteract this, thus demanding more power.

Figure 3-21 Assumed power consumption for the Åsgard system in MW/year.

The main components of the power system are transformers, cables and VSD (Variable Speed Drive). From the source on land the power passes through a step-up transformer where the voltage is increased to minimize voltage drop and losses. Through long cables the power is led to the subsea system where the voltage is decreased in a step-down transformer. The next step is a VSD which modifies the power and voltage for the motor, the recipient. The figure shows a future solution for the power grid with a VSD subsea.

Figure 3-22 Future solution for the subsea electro system.

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3.6.1 Single line diagram and load list First step in the planning of the electric system is to make a single line diagram Simplified overview of the current’s flow from the source to the recipients Drawn in program where the system can be simulated (EDSA)

Figure 3-23 Single line diagram for Åsgard.

A load list, overview of the power need for each unit in the system, is made. The running load is the design variable. Description

Rating Running load MW PF eff. # MW

Intermittent # MW

Max MW

12.5 0.8 0.87 0.4 0.82 0.85

-

14.3 0.47

Main power system Compressor motor Condensate Pump motor

Rating kW

1 1

14.3 0.47

Running load # kW

-

Intermittent # kW

Max kW

2 1

0.002 0.05

0.06 0.002 0.05

1

21.6MJ charging time 12 h

0 0 0 1

0 0 0 0

Auxiliary power non critical loads (loads that will be disconnected when the main power system is disconnected) Cooling Pump Pre-charging VSD Pre-charging Transformers

0.025 0.001 0.05

UPS re-charging

21.6MJ

VSD Compressor VSD Pumps Control system & anti surge *) Circuit breaker module – control

2,5 1 0,3 0,3

2 0 0

1 1 3 1

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0.060 0 0

2.5 1 0,9 0,3

2.5 1 0.9 0,3

Description Circuit breaker module – operation Aux/control Trafo losses

Rating

Running load

Intermittent

Max

2,5

0

0

1

2,5

2,5

1

1

1

0

0

1

4.4

1

4.4

1

0

4.4

9.5

0

0

1

9.5

9.5

15 1

0 1

0 1

1 0

15 0

15 1

Auxiliary power critical loads (loads that will be supplied by UPS during shut down, start up) UPS either locally or central Magnetic bearing system Magnetic bearing system – transient Electric actuator *) Electric actuator – control *)

Figure 3-24 Load list.

3.6.2 Calculations and analysis To do calculations and analysis data on source and equipment plus information about depths and distances is needed. With an overview of loads and a single line diagram calculations and analysis can be performed. Examples of calculations and analysis:  Transmission: flow of the current through the system to discover the voltage drop in cables and components  Voltage election: the voltage level has to be maintained through the system  Start-up of motor: the system must endure start-up of motor, the voltage drop cannot exceed 20% at direct online start of motor  Harmonics calculations: noise fed back from the VSD to grid must be determined and minimized if possible. There are limitations on allowed noise on the grid. The distance between VSD and motor must be minimized to avoid noise if there is no filter. For the time being topside VSD with filter and a long cable to subsea system is used. The benefits of locating the VSD subsea is to save cable cost and cable installation cost. With VSD topside a separate cable from topside to each motor subsea is needed, but for VSD subsea one cable will be used from topside to subsea system, and then relatively short cables from the VSD to motors.  Protection  Short circuit: Power components have to be rated for the short circuit level of the power grid

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3.7 Modules 3.7.1 Retrievability Retrievable in the subsea production/processing dictionary means that a unit can be retrieved and brought to the surface separately for maintenance or replacement and then reinstalled. This type of subsea activity is called intervention. 3.7.2 Modules The reason why units are divided into modules that can be retrieved separately is that the module is too heavy to be lifted in one piece (with a normally sized ship) or that the unit has a high failure rate (electric equipment, rotating machinery) and will need maintenance or replacement during the system’s lifetime and should therefore be easily retrievable. Electric equipment can have a high failure rate due to complexity and vulnerability and will be assembled in a retrievable control module. Rotating equipment (pumps, compressors) also has to be separately retrievable. For the processing system as a whole one aims for redundancy, so that the production will continue with the same or reduced rate even though a component is retrieved. 3.7.3 Module weights, ship accessibility Modules that will need retrieval are built as light as possible to ease the lifting process. The client decides on a max. module weight. Maximum module weights depend on which ships that are available generally and when the retrieval has to be done. Typical weight limits are: 50t, 200t, 400t, 1000t where lifts over 50t are considered as very demanding. Another reason for keeping the module weights low is that the bigger the ship the more expensive the day rate. 3.7.4 Wire weight The deeper the water where the modules will be placed, the longer the wire you will need to lower them. Longer wire will increase the total weight and the module will have to weigh correspondingly less. Weather (wave environment) and location (some countries have more ships available then others) will influence on possible module weights. There are different connectors used for connecting flowlines and modules. Each connector type needs a special tool to assist the connecting and different methods are used for connection (horizontal and vertical). This will be discussed further in chapter 4.8.

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Figure 3-25 MPSV (Multi Purpose Vessel) Bourbon Jade has a lifting capacity of 100 t (at 0 meter depth) which is the same as 63 t on 1500 meters depth.

Figure 3-26 Part of modularization on Tordis.

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3.8 3D construction 3D construction is done from early to end phase, from studies to projects. The models are made to get an overview of the system. It is important to make the models early in the process to see if it possible to construct the system, and update them throughout the project. From the model, ProEngineer will produce detail drawings which will be the basis for future construction. A BOM (Bill of Material) is also provided, this is an overview of all components needed in the system.

Figure 3-27 3D drawing of compressor pilot station for Ormen Lange

The models are drawn on the basis of system drawings from the processing department and information from people involved in the project (electro, process, controls). One needs information about depths, design pressure and all major components. Structure is built around the mayor components and to facilitate the work, standard elements are used where possible. Safety structure is designed for components (if not provided by subcontractor). Distance between components is decided by possible inclination of the pipes (angles etc. is decided by the processing department). Pipes have to be designed for pressure and flexibility for connection and thermal expansion must be taken into account. Regarding modularization what is to be part of each module must be decided (for example valves belonging to pump on same module as the pump) and space to connect/disconnect and ROV access (0,5 m free space on each side). Valves and connectors must be drawn and access for the ROV to open/close them must be considered. Forces must be calculated to see if the structure is stable. Weight must be calculated for the process module as a whole and for the smaller modules during the project to make sure they can be lifted with the planned ship/equipment. By entering density of the 41

materials used, ProEngineer can estimate weight from the volume of the components. Modules or areas on the structures can be chosen and the program will find their weight and center of gravity.

Figure 3-28 3D drawing of Ormen Lange compressor station compared to a hummer

3.9

Technology gap

If there is technology that during a study is found to be needed in a system but is not available, there is a technology gap. It can be technology not yet developed or not qualified for the environment where it is to be used (subsea). A solution for a subsea processing system is unique and will therefore often contain new elements or elements not previously used in the subsea environment. When the system solution is found, the parts are classified by maturity based on their previous areas of use and the tests performed. FMC have instructions on how to perform a technology qualification. This will be discussed further in the chapter on technology qualification.

3.10 Cost estimation Cost estimation is an estimation of the cost of a system. The cost is the actual price FMC pays to build the system and is not the price the customer will pay. Costing is performed by the product groups. Each group is responsible for its own economy and must ensure they get the right pay for the job performed. The MEL (Master Equipment List) is used as a basis for the costing. This is a list of all components in the system. Cost estimation is done from early phase studies to tender, and the calculations will become more accurate for each step. This is natural because further out in the process more details are known and prices are gathered from the subcontractors.

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Early in the project an estimate of +-40-30% is used while the real cost has to be calculated for the tenders (also called budget price). Based on cost of a system a price is determined and this is what will be presented to the client. Different tools are used to evaluate cost. Some of these are: -

Excel for weight estimation (cost per kilo) 3D Drawings (volume and weight) Experience and rule of thumb

Budget prices

-

Access Database – Database is filled with information/quote from sub-vendors and product groups

Tender

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4 Products This chapter presents the products used in processing systems developed and delivered by FMC.

4.1 Separators Separators part fluid phases, i.e. gas, oil, sand and water Value drivers for subsea separation:  No need for transporting water and sand to the surface  Higher separation pressure results in lower hydrocarbon density and makes it easier to separate the oil phase  Higher temperature results in lower viscosity and makes it easier to separate oil and water  Separation closer to the reservoir and with higher pressure gives less emulsion  Less mixing of fluids from different reservoirs  Less slugging and flow instability in the inlet of the separator The separation is done in stages and by different methods. Separators are normally named by the phases they separate or by which method they use, but every unit is unique and designed for the system in which they operate. The three main separation categories are: 

Liquid /liquid separation - separation of water and oil



Gas/liquid separation - separation of gas and liquid so that gas and liquid can be treated separately/brought separately to the destination



Sandhandling system - removal and transportation of sand

There are different types of separators and equipment that can be used for each of these categories. The specific equipment chosen in a project will depend on several factors, e.g. flowrates, fluid properties, water depth etc. 4.1.1 Liquid/liquid separation In a liquid/liquid separator the produced water is separated from the oil. The water can then be injected into a reservoir for either disposal or pressure support. Pressure support means that the water is injected into the reservoir to partly counteract the pressure reduction that is caused by removing oil, water and gas. The higher the pressure in the reservoir the more oil and gas can be produced. If the water is injected for pressure support the quality requirements will be strict and the water will need further treatment to 44

remove residual oil and sand. Removing water from the well stream decreases the pressure loss in the flowlines to topside so the production can be increased. Five types of separators used for bulk water removal are presented in the following:      

Conventional gravity separator (sand, oil, water and gas in the same tank) Semi compact gravity separator (gas bypass line) Pipe separator Dewaterer Decanter Hydrocyclones

Conventional and semi compact gravity separator The conventional gravity separator and the semi compact gravity separator have the same functional principle. A multiphase flow enters the separator and goes through a momentum breaker which separates oil and gas. Additionally, the momentum breaker’s function is to reduce incoming moment, prevent formation of drops from rough contact with the bottom of the separator and prevention of foam by controlling the shear forces by using smooth surfaces. There are different types of momentum breakers, i.e. cyclones and Evenflow. The gas rises and gather in the uppermost part of the separator (conventional separator) or is led through a pipe (semi compact separator).

Level sensors

Combined oil/gas outlet

Gas by-pass line

Inlet cyclone

Water outlet Oil-water separation section Distribution baffles

Figure 4-1 Conventional gravity separator

Sand removal system

Figure 4-2 Semi-compact gravity separator

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Figure 4-3 Flow patterns in gravity separator

When the flow exits the momentum breaker there will be turbulence and gas, oil water is mixed. The flow is therefore lead through baffles plates (one or two), which are vertical plates with holes. In this way the flow is straightened making sure everything moves in the right direction so the separation will begin. Because of the different densities of the fluids they will be separated in layers: sand will gather in the bottom, then water on top of this, then the oil and on top the gas. Bubbles will rise and particles will sink. Sand is normally sedimented within the first two meters of the tank. The retention times in the tank are chosen after the quality of the separation required. The necessary retention time will vary by the composition of fluids and will determine the dimensions of the tank.

Conventional

Semi compact

Advantages  Simple process  Low pressure loss  Robust  Broad experience from topside applications  Smaller than the conventional  Cope with variations in flowrates and slugging

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Disadvantages  Big and heavy  May be unsuitable for separation of heavy oil or well fluids with small amounts of water  May be unsuitable for separation of heavy oil or well fluids with small amounts of water

Figure 4-4 Comparison of size for conventional and semi-compact gravity separator

Pipe separator The pipe separator is a long gravity separator. It is suitable for fluid compositions with heavy oil and small amounts of water. At the inlet, a gas harp separates the bulk free gas from the liquid. The gas is routed to an outlet section and recombined with the oil. The liquid and remaining gas enters the pipe separator where oil and water phases are separated. The layers of oil and gas have different velocities. Because of this the layers will rub out the drops in the emulsion layer and make water drops merge with water drops and oil drops merge with oil drops. The decomposition of emulsion is efficient. Sediments will have sufficient time to sink to the bottom of the pipe because of the relatively small diameter. The pipe diameter is based on a design velocity of approximately 0.7 m/s. At the end of the pipe separator an outlet section splits the separated liquid phases.

Figure 4-5 Pipe separator

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Figure 4-6 Parts of Marlim SSAO separation module, showing gas harp and gas crossover (red), PipeSeparator™ (green) and outlet section (grey). White arrows indicate direction of flow in the PipeSeparator™.

Inline Dewaterer

Figure 4-7 Inline DeWaterer

The InLine DeWaterer is a compact cyclonic unit designed for efficient separation of bulk oil from water. The unit consists of one or more axial flow cyclones with fixed swirl elements. The technology has been developed and qualified in cooperation with Statoil. The mixed oil-water flow enters the pipe spool (or for multiple liners a DeWaterer vessel) via the inlet nozzle and moves into the inlet compartment. Next, the mixed flow goes into the DeWaterer liner where it moves through the fixed swirl element generating a rotating flow. The centrifugal force makes the lighter phases, i.e. oil and gas, move towards the centre of the DeWaterer. The heavier phases, (i.e. water and sand) move to the outside of the liner. The lighter phases are extracted (counter current) through the reject, and the heavy phases are removed via the underflow. 48

A major advantage of the system over the conventional gravity-based solutions is a potentially large reduction in the required vessel size. A reduced vessel size leads to a reduced overall station size and weight. DeWaterer is able to handle up to 30-50 % gas volume and both oil- and water continuous systems. Reject flow is normally around 15-25% of total incoming flow. For deoiling of a water stream, OiW outlet quality is typically