FUNDAMENTALS OF SUBSEA ENGINEERING

Module 5 Reliability, Maintenance and New

Technologies

John Preedy PhD

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CONTENTS

Learning Outcomes ....................................................................................................................... 4

1. SUBSEA INSPECTION MAINTENANCE AND REPAIR (IMR) ............................................... 5

1.1 Introduction to IMR ................................................................................................... 5

1.1.1 Diver Assisted and Diverless Requirements ....................................................... 5

1.2 The Role of Inspection and Monitoring in Failure Avoidance ............................................ 7

1.2.1 Reliability of Inspection ................................................................................... 8

1.2.2 Types of Damage and Defects.......................................................................... 8

1.3 The Regulations Relating to Inspection ...................................................................... 11

1.3.1 The Requirements of Inspection ..................................................................... 12

1.3.2 Underwater Inspection Programme................................................................. 12

1.4 IMR Operations ....................................................................................................... 12

1.5 Philosophy ............................................................................................................. 13

1.6 Programme Definition .............................................................................................. 13

1.7 Typical ROV Fleets .................................................................................................. 15

1.8 Field Engineering Records and IMR Database .............................................................. 17

1.9 Summary of ROV and AUV Devices and Technologies .................................................. 18

1.9.1 Part A Remote Operated Vehicles (ROVs) ..................................................... 18

1.9.2 Part B Autonomous Underwater Vehicles (AUVs) ........................................... 27

2. SUBSEA WELL OPERATIONS.......................................................................................... 30

2.1 Introduction to Well Workover .................................................................................. 30

2.2 Well Intervention and Well Workover ......................................................................... 34

2.3 Subsea Well Intervention Categories ......................................................................... 34

2.3.1 Light Well Intervention (Also Referenced as Type I or Class A in Literature)......... 34

2.3.2 Medium Well Intervention (Also Referenced as Type II or Class B in Literature) ... 35

2.3.3 Heavy Well Intervention (Also Referenced as Type III or Class C in Literature) .... 35

2.3.4 Well Heavy Workover ................................................................................... 35

2.3.5 Light Workover Activities ............................................................................... 36

2.3.6 Types of Well Work ...................................................................................... 37

2.4 Subsea Well Workover ............................................................................................. 38

2.4.1 Types of Well Interventions ........................................................................... 38

2.4.2 Equipment Required ..................................................................................... 38

2.4.3 Subsea Well Servicing by Subsea Lubricator .................................................... 39

2.5 Development of Coiled Tubing Operations for Subsea Wells .......................................... 42

2.5.1 From Drill Rig/Drillship/MODU ........................................................................ 42

2.5.2 Uses ........................................................................................................... 43

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3. NEW TECHNOLOGIES FOR SUBSEA PRODUCTION SYSTEMS .......................................... 45

3.1 Subsea Multiphase Pressure Boosting/Separation ........................................................ 45

3.1.1 Why Subsea Boosting/Processing? ................................................................. 46

3.2 Subsea Multiphase Pumping ..................................................................................... 47

3.3 Systems ................................................................................................................ 49

3.3.1 Multiphase Booster Pumps............................................................................. 49

3.3.2 Partial Subsea Separation Pressure Boosting Systems ...................................... 56

3.4 Full Subsea Separation ............................................................................................ 59

3.5 Other Seabed Processing ......................................................................................... 59

3.5.1 Subsea Separation and Re-injection of Produced Water..................................... 59

3.5.2 Seabed Raw Water Injection .......................................................................... 61

3.6 Subsea Electrical Power Distribution .......................................................................... 62

3.7 Recent Headline Field Utilising New Technologies ........................................................ 62

3.7.1 King Field, Gulf of Mexico (BP) ....................................................................... 62

3.7.2 Ormen Lange Gas Field, Norway (StatoilHydro)................................................ 64

3.7.3 Tyrihans Field Tie-back, Norway (Statoil) ........................................................ 66

3.7.4 TORDIS IOR Project Norway (Statoil) ............................................................. 67

3.7.5 Marlim Field, Campos Basin Brazil (Petrobras) ................................................. 71

3.7.6 Pazflor Field Development, Angola (Total) ....................................................... 72

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LEARNING OUTCOMES

Learning Outcomes:

On completing this module you will have an understanding of: The importance of planning for inspection, maintenance and repair (IMR) in the design, construction, installation and operational phases of an offshore field development. The place of divers and ROVs in IMR and their limitations. The difference between a well intervention and a well workover, the reasons for each activity and the complexity of such activities. The need for artificial lift and the main ways that this can be accomplished.

You will be able to: List the aims of structural inspections. List the types of defects, the causes and relative risk they pose to the operations, to the structure and pipelines and risers. Describe the elements of the IMR philosophy and how it underpins the IMR programme. List the basic reasons why well interventions have been required in the past. List the different types of well intervention. Describe the advantages of a subsea wireline lubricator and its major components. Describe the advantages and disadvantages of coiled wire tubing operations and its main uses. List the different types of artificial multiphase boosting pumps and how they are used.

You will also have insight into: The requirement and means to store a vast amount and range of data which will need to be readily accessed by many different people in different locations. The scope and range of ROVs and AUVs. Subsea gas boosting. Partial subsea separation and pressure boosting systems. Full subsea separation equipment through Aker Solutions and FMC Technologies. The application of the technology in a spectrum of field developments.

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1. SUBSEA INSPECTION MAINTENANCE AND REPAIR (IMR) 1.1 Introduction to IMR

Figure 1.1

Summary of underwater engineering (divers or ROVs for installation plus Inspection, Maintenance and Repair IMR); subsea well intervention workovers; new technologies of

seabed pressure boosting and separation Source J E & P Associates and Azur Offshore Ltd

Subsea IMR means the inspection, maintenance and repair of underwater structures. These structures may comprise:

jackets; templates; manifolds; wellheads and trees; risers and riser systems; flowlines; pipelines and so on.

This section is an introduction to the problems of the management of subsea IMR programmes for a range of offshore structures. IMR considerations must be taken into account during the design, construction, installation and operational phases of subsea operations. The activity must include planning of the programme, setting up suitable databases, and management of the information generated by the IMR programme. The IMR team must have a comprehensive capability including project management, structural engineering, subsea engineering, underwater engineering systems analysis and software development. Lines of communications, the flow and storage of information are also a prime consideration. 1.1.1 Diver Assisted and Diverless Requirements As a preface to a discussion on IMR activities it is necessary to examine the basis of the proposed underwater work using divers or ROV systems. During the early years of offshore production in shallow waters, divers were automatically an integral part of construction and IMR activities. Examples of a construction activity (tie-in of spool piece at the base of a jacket + installation of pipe protection concrete horseshoes) and a monitoring activity are given. During this period all underwater systems were designed with the use of divers in mind.

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(a) (b)

Figure 1.2

Examples of Divers Working

Figure (a) shows two divers connecting a spool piece between a flowline and a riser. The divers are lowered to the seabed in the diving bell. The two divers work together for safety. They are assisted by the eyeball ROV which provides additional lighting TV pictures to the diving support vessel above. The

spool piece is lowered to the seabed from the vessel using a handling frame. The divers manoeuvre the spool into position and connect the flange ends with nuts and bolts using simple hand tools.

Figure (b) shows divers lifting horseshoe shaped concrete structures to protect pipelines from dropped

objects. Again two divers work together for safety.

Source Rockwater The trend to deeper applications led to the need to develop robotic type systems that avoided the use of divers. A remotely operated vehicle (ROV) is a tethered underwater robot. It is linked to the ship by a tether (sometimes referred to as an umbilical cable) a group of cables that carry electrical power, video and data signals back and forth between the operator and the vehicle. High power applications will often use hydraulics in addition to electrical cabling. Most ROVs are equipped with at least a video camera and lights. Additional equipment is commonly added to expand the vehicl capabilities. These may include sonars, magnetometers, a still camera and a manipulator or cutting arm. Current deepwater installation and IMR activities are carried out using ROVs in combination with a tool sledge. This combination emerged after a general period of development looking at robotic devices. The system comprises the use of relatively standard ROV units (having mobility, lifting, control and manipulation capabilities) which can be connected to task-specific tool skids which carry specific tooling packs and spare components.

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Figure 1.3

Remote Operated Vehicle (ROV) and Tool Skid Combination The ROV is a unit provided by a number of different suppliers (here Sonsub). This has a propulsion system, lights and cameras, and manipulator(s) arms. It is powered and controlled from the surface

through an umbilical. The separate tool skid is a task-specific system which can be mated to the ROV. The example shown is of a diverless flowline connection system skid.

Source Sonsub Saipem In deepwater, diverless systems are essential. Nowadays, in shallow water diverless systems may be preferred for some tasks because the overall costs may be cheaper than the very costly alternative of divers requiring all the safety systems. This is particularly true in IMR activities. 1.2 The Role of Inspection and Monitoring in Failure Avoidance Underwater IMR accounts for a significant proportion of operational expenditure and is usually subject to detailed scrutiny by installation managers as they grapple with the problems of maintaining production while reducing operational costs. Increasingly, risk-based approaches to IMR are being developed by operators to meet this challenge. The aim of structural inspection has traditionally been interpreted to mean: 1. The detection of any defects, damage or deterioration which may impair local or overall structural

safety and serviceability. 2. The identification of reasons for the existence of such defects and damage. 3. The evaluation of possible consequences to justify repair or further monitoring of defects. Inherent in this interpretation is the concept of risk. Current regulations require that the risk of structural failure to be maintained at acceptably low levels

low as reasonably or ALARP criteria apply). This requirement can be met in large part by safe design and construction practices combined with operational procedures which prevent or minimise structural damage. However, structures can be accidentally damaged, for example, by dropped objects, vessel impacts or storms, and all structures will deteriorate with age due to corrosion and corrosion fatigue processes. If left unchecked, these processes will eventually cause structural failure. Structural inspection provides a means of detecting damage before failure occurs and is thus an important element in failure prevention.

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1.2.1 Reliability of Inspection Currently, underwater inspection relies heavily on visual techniques using specially designed underwater video cameras and stills cameras carried either by diver or by ROVs. Increasingly, advances in ROV technology are leading to less reliance on the diver with significant savings on cost and a potential reduction in the frequency of diving accidents. Nevertheless man is always in the loop. Inspectors are needed to recognise and judge whether visual indications are in fact defects and to assess the significance of any defects found against acceptance criteria (for example, comparing actual defect/damage size against allowable defect sizes). The look see recognise sequence is an identification process which in some areas is enhanced by the use of non-destructive testing (NDT) techniques, as for instance in the case of magnetic particle inspection (MPI) for identification of surface breaking cracks at welded joints. In other cases NDT is used to verify that a defect identified visually is actually present, or it is used to size a defect. The presence of defect does not necessarily mean that a repair has to be carried out immediately; it may be perfectly acceptable to leave a defect and simply monitor its progress for a while. The particular decision taken will depend on the significance of the defect. Fracture mechanics, or its statistical derivative, probabilistic fracture mechanics, is generally used to support this task. 1.2.2 Types of Damage and Defects Structural Defects The nature and number of defects found on a structure significantly influence the inspection programme. The typical defects found on a structure are summarised here. The most common defects are surface breaking cracks in or near the node points. These defects pose the greatest potential risk to the structure and so much detailed inspection is focused on and around the welds. Other defects which may need to be detected include:

Sub-surface cracks. Internal cracks. General metal loss and corrosion pits. Knife line grooving corrosion at welds. Dents and gouges.

Figure 1.4

Platform Structure Inspection

The structural members of a platform are inspected to check the levels of corrosion and important node welds. Often representative nodes are selected for the periodic inspections as represented on the

simplifying schematic. Inspections for metal thickness and weld are logged onto an appropriate record sheet to monitor ongoing performance.

Source Azur Offshore Ltd

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Figure 1.5

Manifold Inspection Manifold piping could be subject to corrosion (both external and internal) and erosion from any sand in the production flow. During design and manufacture certain test points in the manifold piping will be defined for ongoing inspection, wall thickness in particular. These test points will be visited during the inspection programme and the measured values recorded as a record of the loss of wall thickness over

the life of the manifold. Source J E & P Associates

Other parameters which need to be monitored on the structure include:

The type and extent of fouling. Damage to coatings (where present). Cathodic protection potentials and currents.

Pipeline and Riser Defects The integrity of pipelines and risers is particularly important since loss of containment can lead to a major accident. The most frequent cause of pipeline and riser failure is corrosion. For risers, metal loss due to external corrosion can cause loss of containment, particularly in the splash zone and above, and so external corrosion represents a significant risk. For submerged pipelines (as distinct from risers), external corrosion failures have not (to date) occurred in the North Sea. This can be put down to two factors: (i) pipeline cathodic protection (CP) systems are generally designed to a high specification; and (ii) prior UK legislation insisted that pipelines were regularly inspected and cathodic protection potentials

maintained at levels less than 900 mV relative to the silver potential. Inspection and monitoring of the corrosion control systems (coatings and cathodic protection) forms an important element of pipeline and riser inspection procedures.

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Typical inspection items on pipelines and risers include:

Corrosion defects and pits. Corrosion at welds. Fatigue cracks. Impact damage to coatings. Dents and gouges. CP potentials and currents.

Some of the above defects, especially corrosion, dents and gouges, can now be detected from the inside of pipelines using pipeline inspection vehicles. External damage to coatings and the level of cathodic protection are generally inspected using ROVs.

Figure 1.6

Pipeline and Flowline Inspection ROVs Note a free flying ROV deploying sonar and visual camera instruments; the second a tracked ROV which

runs along the pipe making contact measurements. Source SAAB

Causes of Defects Damage or deterioration on a structure arises from one or more of the following cause categories: (a) Deterioration of material as a result of the environment:

(i) Corrosion. (ii) corrosion fatigue. (iii) stress corrosion cracking. (iv) wear/erosion.

(b) Overload of the environmental conditions. (c) Accident or third-party damage. (d) Human error/gross error.

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There is clearly some overlap in these categories. For example, one form of human error is design error which could lead, say, to insufficient structural strength which could then result in an overload by the environment. Another example of human error is in the incorrect material selection which could result in more rapid deterioration of parts. 1.3 The Regulations Relating to Inspection All areas where offshore production exists will have national regulations relating to inspection. In the UK, since 1996, SI 289 has been replaced by four new sets of Regulations which are now having a significant impact on inspection strategies. These are: 1. Offshore Installations (Safety Case) Regulations (SCR: 1992). 2. Prevention of Fire and Emergency Response Regulations (PFEER: 1995). 3. Design and Construction Regulations (DCR: 1996). 4. UK Pipeline Safety Regulations (PSR: 1996). These Regulations take a completely different approach in that they place responsibility on the installation managers to ensure that the integrity of the installation is achieved. Risk-based inspection (RBI) is the approach which the offshore industry is now adopting. In this new approach, in-service inspection plans are based on risk assessment of the structure which implies an assessment of the likelihood of failure and the consequences of failure of structural components. Inspection provides the information necessary to predict the likelihood of failure and the potential consequences.

Figure 1.7

Risk-based Inspection Methods Some regulatory authorities call for annual inspections of seabed items. Areas using the safety case

approach leave the timeframe for inspections up to the operator. An RBI approach enables the operator to focus the effort where it is most appropriate, and thereby allowing a more efficient use of the

inspection budget. Source J E & P Associates

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1.3.1 The Requirements of Inspection The purpose of any inspection programme is to detect defects, damage and deterioration which may impair structural reliability. It is important to identify the reasons for the existence of defects found since this may well determine future growth rates and will influence problem solutions (for example, local strengthening rather than cut out and replacement). Decision options such as choice of repair method or monitoring are dependent on the risk of failure and hence are closely linked to the inspection programme and their results of inspection. 1.3.2 Underwater Inspection Programme Underwater inspection is expensive and any activity represents a risk to the divers who carry out the work. Consequently careful advanced planning is essential. In order to ensure that a subsea structure is safe and reliable the inspection programme needs to consider the spatial distribution of damage, the frequency of occurrence of damage generation events, the growth of defects over time and the tools to be used to find and assess the damage. Stated simply, this means deciding what and where to inspect, when to inspect and how to inspect. On offshore structures the areas that need to be inspected include:

Subsea risers and conductors. Sea water intakes and caissons. Oil and gas flow lines. Jacket members and legs. Conductor guide frames. Nodes. Subsea production systems. Pipelines and flow-lines.

In addition to identifying the items which need to be inspected, a number of other factors need to be considered including:

The particular task(s) to be carried out. The manpower requirements. The most effective intervention method. The equipment to be used. The task sequence. The environmental constraints. Acceptance criteria.

The majority of underwater inspection is a combination of visual inspection backed up by NDT techniques for detailed assessment of suspect areas. This is preceded by any cleaning of the steel that may be necessary in order to carry out the inspection activity. 1.4 IMR Operations The overall requirements during inspection, maintenance and repair operations can be defined as: Control of Planned Maintenance

Job definition. Planning. Cost forecast. Cost control.

Safety Assurance

overall responsibility for safe and economic production. Statutory requirements (certification and re-certification).

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Operating Requirements and Special Tasks

Engineering of minor modifications. Integration of modifications into maintenance plans. Integration of repairs.

Data Handling

A library function. 1.5 Philosophy Operators pay considerable attention to the formulation of what may be termed an

. When an inspection is in the ideal position of being able to start a new development (where past operational practices and systems present no handicap), formulation of a suggested inspection philosophy for IMR should:

Separate the beneficial from the ineffective current techniques and practices. Assess the latest but proven techniques, identifying and separating the real from the claimed capabilities. Investigate and assess developing methods and techniques which may be expected to be available in the future. Evaluate all future tasks defining frequency, task, and whether interventions are likely to be diver-assisted or diverless.

In particular, this assessment should include all relevant underwater inspection activities, such as:

General inspection. Marine growth inspection. Debris survey and mapping. Seabed, scour and structure stability inspection. Corrosion inspection and projection profiling. Underwater cleaning. Still photography, photo formatting and presentation. Videography, operation and accessories required. NDT inspection including: o MPI (more than 15 possible techniques). o Ultrasonics (compression and shear wave). o Acoustic methods. o Vibro-detection. o Corroscan (risers and pipelines). o Harwell ultrasonic torch. o Photogrammetry (physical damage assessment).

This work must conform to the requirements of the operator, government regulatory body/HSE and certifying authorities. These documents should be established so that all work for the full five-year cycle is scheduled within the defined requirements, with the utmost efficiency, and with adequate flexibility to be able to respond to progressive experience gained by operation of the various structures and installations. 1.6 Programme Definition Based on the above philosophy, the system IMR programme can be developed. It should include consideration of the following aspects:

Scope of work. IMR management team. Database requirements, definition and design. Database co-ordination and logistics.

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Fabrication inspection. As-built base line data acquisition covering: o Photographic and video records. o Material thickness measurements. Formal procedures for critical tasks. Specialist supervision.

Scope of Work This should define the requirements to a diving or ROV contractor and allow him to tender for the work. IMR Management It is essential that control of the inspection activities defined in this report should be centrally managed and co-ordinated by an appropriate qualified and experienced underwater engineer and a topside engineer under the control of the maintenance manager or supervisor. Database Requirements Definition and Design Define what information should and should not be sought, kept and processed. As a result of this collaborative work between all parties, the database would satisfy the essential requirements of achieving all data required over the life of the structure, without swamping the system with unnecessary data. Subsea Markers All offshore installations are subject to fouling by marine growth, which leads to lengthy inspection procedures by diver and ROV. In very murky or fast flowing water, it is very important that the diver or ROV pilot is fully aware of the location. Conventional painted or metal marking systems are quickly rendered useless. Subsea markers have been developed to allow each focal point to be uniquely marked with large, non-fouling material, bright signs as shown. A logical marking grid system using letters and numbers can be used to ease orientation even further. Database Co-ordination and Logistics Co-ordination of collaborative inputs to the database and maintenance of database integrity is seen as requiring full-time attention by the relevant engineers. This is particularly important during phases of continuous influx of database information from fabrication sites, but also during the operational phase for the logistics of ordering and procuring spare parts and new equipment. Maintenance planning, work orders, planned shutdowns, cost control, accounting interfaces, warehousing and offshore stock control, vendor response time, offshore cargo movements and so on are all part of the logic diagram. Fabrication Inspection There are two distinct functions which will be beneficial to the operator: (i) First review by the inspection contractors of reports by an appropriate specialist NDT

technologist to ensure that the data serves the needs for future inspection/maintenance. (ii) Second preparation of base-line data regarding relevant as-built physical features, dimensions and

so on. As-built Base-line Data Acquisition Care with establishment of as-built details and accurate recording of as-built features can be expected to have continuing benefits in facilitating inspection (and its interpretation) and maintenance throughout the life of the field. Reference to photographic records of the as-built appearance of all relevant joints and features offers substantial benefits. These benefits mainly comprise two aspects: (i) Photographic records of critical areas, for subsequent reference over the years of operation. (ii) Valuable assistance to divers in their underwater navigation. Significant tolerances are allowed on the thickness of plate materials supplied, which can cause confusion with subsequent underwater measurements. Therefore, it is recommended that:

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(i) be nominated and marked at which thickness readings will be required during in-service underwater thickness surveys.

(ii) Accurate and definitive base-line survey information be acquired regarding the material thickness at those

Formal Procedures for Critical Tasks It has been common industry practice in the past for subsea inspection contractors to specify their preferred procedures for certain activities. While this has had the benefit that such procedures were defined to the operator at no cost to the operators, experience has shown that such preferred procedures are sometimes ineffective and, therefore, not cost effective. Operators have adopted an alternative approach of commissioning IMR experts to prepare formal procedures (referenced to acceptable codes and authorities), which utilise up-to-date and proven techniques and practices. These are then used as which are imposed on any contractor employed by the operator. This approach helps one to ensure consistent practices and results from year to year, and from one contractor to another, with maximum assurance of continuity of results. Specialist Supervision t should be stressed that specialist supervision of annual subsea inspections will ensure that planned programmes and schedules are achieved, and that the work is actually performed as intended and according to the stipulated procedures approved by the operator and the certifying authority. 1.7 Typical ROV Fleets A range of typical ROVs are illustrated in Figures 1.8 to 1.11.

Figure 1.8

Eyeball ROV Seaeye Tiger

ROVs with cameras and light sets for inspection and observation. Note some may have a simple manipulator but this is for attaching to a grabber bar on the subsea equipment item to hold the ROV

stationary for detailed photographs to be taken of significant features such as the node welds. Source SAAB

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Figure 1.9

Work Class ROV Seaeye Cougar XTi and Seaeye Panther-XT Plus

Source SAAB

Figure 1.10

Schilling UHDTM Ultraheavy-Duty Work-Class ROV System Source Schilling Robotics

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Figure 1.11

ROVs at Work on a Tree Source Wikimedia Commons

Directed Learning: Look up websites of producers of ROVs to collect more information on the various ranges and capabilities. Websites include SAAB: www.seaeye.com and Schilling Robotics: www.schilling.com www.cybernetix.fr/.

1.8 Field Engineering Records and IMR Database Ideally, all systems in a company would use a unified database, based mainly (often exclusively) on a computer system. The database comprises the total records for the design, construction, installation and in-service modification of the structure in a field. Typically this will include design specifications, calculations, construction specifications, construction records (all QA records plus photographs, video and so on), installation reports, as-built drawings, vendor equipment data and so on. It can be seen that the database is likely to involve a wide variety of storage media including paper, microfilm, CAD, photographs, video and samples. However, all these data can either be stored digitally on the computer or the originals catalogued and referenced by computer with perhaps automatic access in some cases. Furthermore, it is likely that all drawings will be CAD. The second system referred to above (the IMR system database) contains information specially extracted from the engineering records system plus all the information needed to plan, execute and record the IMR programme, as defined earlier in this section. Why a Database? A database is no more than a centralised and integrated collection of data and should be computer-based by preference. For offshore structures there is an especially strong case for using computers to store the data used and generated by the maintenance effort. Microfilm copies of design documents and detailed drawings plus video and photographs and so on are integrated into the system by detailed indexing stored on computer files. The case for such a system is as follows:

Large volumes of data needing to be stored. Data will need to be accessed by many different persons in different locations including offshore. Data are continuously updated and augmented from many different sources and must be stored centrally with proper indexing. For any particular problem, many different items of information need to be assessed and collated

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Computer storage of information leads to the development of software for management for example: o Planning, network analysis and scheduling. o Trend analysis (technical and economic). o Forecasting requirements.

Figure 1.12

IMR Data Flow

The inspection work generates a large amount of data in several forms numerical measurements, still photographs and videos. Such information will be collected over a time base, for example as-built, as-installed and periodically throughout the field life. All this information must be stored in a retrievable

manner for use by the host production facility, the operator and the IMR contractor. Source J E & P Associates

1.9 Summary of ROV and AUV Devices and Technologies 1.9.1 Part A Remote Operated Vehicles (ROVs) ROVs comprise the following components:

Figure 1.13

The Control Unit Source Azur Offshore Ltd

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Figure 1.14

Launch and Recovery System

Source Azur Offshore Ltd

Figure 1.15

The Main Umbilical

Source Azur Offshore Ltd

20

Figure 1.16

The Tether Management System

Source Azur Offshore Ltd

Figure 1.17

The Vehicle

Source Azur Offshore Ltd

21

Figure 1.18

Cameras

Source Azur Offshore Ltd

Figure 1.19

ROV Sensors

Source Azur Offshore Ltd

22

Figure 1.20

Positioning and Navigation Systems

Source Azur Offshore Ltd

Figure 1.21

Sonar Tooling

Source Azur Offshore Ltd

23

Figure 1.22

Manipulators

Source Azur Offshore Ltd

Figure 1.23

ROV Tooling

Source Azur Offshore Ltd

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Figure 1.24

Running Tools

Source Azur Offshore Ltd

Figure 1.25

Hot Stab Power Connections for Tools

Source Azur Offshore Ltd

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Figure 1.26

ROV Applications

Source Azur Offshore Ltd

Figure 1.27

Rig Support Tasks

Source Azur Offshore Ltd

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Figure 1.28

IMR Tasks

Source Azur Offshore Ltd

Figure 1.29

Deepwater Installation Activities

Source Azur Offshore Ltd

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1.9.2 Part B Autonomous Underwater Vehicles (AUVs)

Figure 1.30

Autonomous Underwater Vehicles (AUVs) The Concept Source J E & P Associates

Figure 1.31

AUVs The Concept and Example Source J E & P Associates

At present AUVs do not carry out installation or repair activities, but are used for seabed or pipeline survey work. The oil and gas industry uses AUVs to make detailed maps of the seafloor before they start building subsea infrastructure; pipelines and subsea completions can be installed in the most cost effective manner with minimum disruption to the environment. The AUV allows survey companies to conduct precise surveys of areas where traditional bathymetric surveys would be less effective or too costly. Also, post-lay pipe surveys are now possible.

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Figure 1.32

Spider AUV SPIDER: a crawling AUV specialised for touchdown monitoring (TDM) during pipelay operations.

Source Nexans

Figure 1.33

Pipeline Survey AUV Swift

The AUV assists installation (sonar studies of the seabed). After installation they are used to monitor the pipeline throughout its life. It is programmed for the mission (sometimes several 100s of km).

It is launched from the support vessel at the starting location. The support vessel then meets it at the finishing point and recovers the AUV. The collected data are then downloaded from its onboard

computers. Such pipeline survey AUVs are used to investigate potential pipeline routes. Source Bluefin Robotics Corporation

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Directed Learning: Look at Cybernetics website for their latest information. www.cybernetix.fr/, You can click to change the language to English. Go to homepage Oil and Gas AUVs Services IMR. At the bottom of the page are two very short

animations on the Swimmer.

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2. SUBSEA WELL OPERATIONS 2.1 Introduction to Well Workover In the past one of the main reasons why operators preferred to develop offshore fields with platform based and operated wells was the drilling risk, the complexity and the subsequent cost of subsea well maintenance. However, over the years, reliability of the subsea systems has greatly improved; new techniques have been tested and used with success on many hundreds of subsea wells where CAPEX and OPEX costs have come down. However, subsea wells do require maintenance activities to keep them productive.

Figure 2.1

Subsea Interventions Well Workover Requirements Typically wells require a workover about every five years.

Source Douglas-Westwood Ltd

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Figure 2.2a

Figure 2.2b

Need for Subsea Interventions and S Experience

Source Douglas-Westwood Ltd

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Typical workover and maintenance activities taken from past statistics based on 10 years of operation of 300 subsea wells in the North Sea show the basic reasons why well interventions are required:

Downhole completion/reservoir problems = 24.1%

SCSSV problems tubing retrievable or wireline retrievable = 34.2%

Subsea control systems malfunctions = 13.8%

Flowline failures = 10.2%

Xmas tree leaks = 6.3%

Marine damage (dropped objects/fishing gears) = 5.1%

Connection leaks = 3.8%

Valve actuator failure (tree/manifold) = 2.5% Problems have to be resolved to bring back these wells to a maximum productivity. Over the life of a well, a number of workovers have to be carried out either by MODU drilling units (semi-sub or drill ship monohull), or well service vessels (WSVs) after a detailed cost/benefit evaluation. Near the end of life, the workover cost could be too high and the decision to shut down the well is normally taken.

Reason to Perform a Workover Workovers rank among the most complex, difficult and expensive types of wellwork there is. The production tubing may have become damaged due to operational factors like corrosion to the point where well integrity is threatened. Downhole components such as tubing retrievable downhole safety valves or electrical submersible pumps may have malfunctioned, needing replacement. In other circumstances, the reason for a workover may not be that the completion itself is in a bad condition, but that changing reservoir conditions make it unsuitable. For example, a high productivity well may have been completed with tubing to allow high flow rates (a narrower tubing would have unnecessarily choked the flow). Some years on, declining productivity means the reservoir can no longer support stable flow through this wide bore. This may lead to a workover to replace the tubing with tubing. The narrower bore makes for a more stable flow.

THESE REQUIRE A FULL WORKOVER RIG

Figure 2.3

Reasons to Perform a Well Workover

Source J E & P Associates

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Figure 2.4

Subsea well intervention requirements demand as percentage of total.

Source Infield Systems Ltd

Inside subsea wells, interventions can be carried out by various means:

Within 500 m: o By drilling rig anchored (above the well, the template or the cluster). o By workover support vessel (WSV) DP operated (monohull or small semi-sub).

Below 500 m: o By drilling semi, DP operated. o By drill ship, DP operated. o By WSV, DP operated.

Subsea well intervention requirements demand as percentage of total

34

Figure 2.5

Heavy Workover Performed from a Drilling Rig In shallow water the drilling semi is moored above the well system. For conventional dual-bore Xmas

trees the tree must first be removed. The guidewires are connected between the rig and the guidebase, and the tree disconnected and brought to the surface. The rig then runs the BOP (blowout preventor) to the wellhead with the workover riser (in fact the marine drilling riser). At this point the well is under the

control of the rig and the heavy workover activity can proceed. Source Azur Offshore Ltd

2.2 Well Intervention and Well Workover A well intervention, or is an activity involving maintenance, modification, repair or completion of an oil or gas well. Well workover more specifically refers to heavy duty or full workover working in the well requiring full well bore access. Well intervention generally refers to the lighter duty tasks performed in wells. Any intervention involving subsea wells is difficult and requires much advanced planning. Light intervention vessels or drilling rigs need to be mobilised at great expense and the intricacy of rigging up onto a spool tree on the sea bed must be faced. 2.3 Subsea Well Intervention Categories 2.3.1 Light Well Intervention (Also Referenced as Type I or Class A in Literature) Light interventions are serviceable using a variety of equipment that can be deployed from numerous types of vessels. The types of operations can be identified as:

Bore hole surveys/logging. Fluid displacement. Gas lift valve repair. Perforating. Re-perforating.

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Sand washing. Setting/pulling tubing plugs. Stimulation. Zonal isolation.

2.3.2 Medium Well Intervention (Also Referenced as Type II or Class B in

Literature) Medium intervention requirements are in general more specialised than the light types. Some are related to the production issues while others refer to safety issues. Examples are:

Casing leak repairs. Fishing. Paraffin, asphaltenes, hydrates. Plugging abandoned well. Remedial cementing. Sand control/gravel packing. SCSSV failure. Water shut-offs.

2.3.3 Heavy Well Intervention (Also Referenced as Type III or Class C in

Literature) The traditional definition of heavy well intervention typically is associated with the deployment of drilling rigs. Examples are:

Tubing packer failure. ESP replacement. Horizontal well sand control. Well completion change out. Re-drilling side tracks. Subsea Christmas tree change out.

2.3.4 Well Heavy Workover The term workover is used to refer to any kind of oil well intervention involving invasive techniques, such as wireline, coiled tubing or snubbing. More specifically, it will refer to the expensive process of pulling and replacing a completion. Operation Before any workover, the well must first be killed. Since workovers are long planned in advance, there would be much time to plan the well kill and so the reverse circulation of appropriate well fluids would be common. The intense nature of this operation often requires no less than the capabilities of a drilling rig. The workover begins by removing the Xmas tree (conventional dual-bore tree) and placing the blowout preventor (BOP) on the wellhead. Then the tubing hanger may be lifted from the wellhead thereby beginning to pull the completion out of the well. The string will almost always be fixed in place by at least one production packer. If the packer is retrievable it can be released easily enough and pulled out with the completion string. If it is permanent, then it is common to cut the tubing just above it and pull out the upper portion of the string. If necessary, the packer and the tubing left in hole can be milled out, though more commonly, the new completion will make use of it by setting a new packer just above it and running new tubing down to the top of the old. Where a spool tree is used the BOP may be landed direct onto the top of the tree, with the workover activities performed through it.

36

Figure 2.6

Horizontal Tree with BOP in Place on Top for Workover Operations With the horizontal Xmas trees the BOP can be landed directly onto the tree using the drilling marine

riser. This saves considerable time and cost compared with the arrangement in Figure 2.5. Source J E & P Associates

2.3.5 Light Workover Activities

Figure 2.7

Lightweight Intervention Performed by a Vessel on Dynamic Positioning (DP) Lightweight intervention vessels are much simpler and of lower cost than a full drilling rig. They all

operate on DP. The range of intervention activities is quite extensive. Source Fishsafe

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2.3.6 Types of Well Work Pumping This is the simplest form of intervention as it does not involve putting hardware into the well itself. Frequently it simply involves rigging up to the kill wing valve on the Xmas tree and pumping the chemicals into the well. Wellhead and Xmas Tree Maintenance The complexity of this operation can vary depending on the condition of the wellheads. Scheduled annual maintenance may simply involve greasing and pressure testing the valve on the hardware. Sometimes the downhole safety valve is pressure tested as well. Wireline Workover The term wireline usually refers to a cabling technology used by operators of oil and gas wells to lower equipment into the well for the purposes of a well intervention. In its simplest and most used form, the wireline simply consists of a single strand of metal wire most commonly or in diameter (sometimes referred to as slickline). In other cases, the wire will be composed of braided strands, rendering it stronger and heavier (called braided line). Braided line can contain an inner core of insulated wires which provide power to equipment located at the end of the cable (called electric line or E-line) and provides a pathway for electrical telemetry for communication between equipment at each end of the cable. The first use of wireline in a wellbore was as a measuring device. Measuring systems using rope or flat section steel tape were over time replaced by wire. Wireline uses include: (a) Slickline. Around 80% of wireline jobs are undertaken using slickline. The nature of slickline

requires any tools to be able to operate independently of electrical communication from the surface. This limits slickline to jobs such as setting plugs and straddles, which require mechanical action. Some completion components may be deployed and retrieved on slickline such as wireline retrievable safety valves, downhole gauges (assuming that communication and power requirements are met by other means), perforating, setting explosively set bridge plugs and gas lift valves. Slickline can also be used for fishing, the process of trying to retrieve other equipment and wire, which has been dropped down the hole.

(b) Electric line. Electric line is used for well logging, which involves deploying sensory tools designed to

provide some information about the properties of the well. Electric line operations can be divided into two domains: reservoir evaluation (or which operates in the borehole just after it has been drilled, and production (or which operates after the well has been completed and lined with a metal pipe (the

Reservoir evaluation focuses on recording the properties of the formation around the borehole (density, porosity, oil and water saturation, moveability of hydrocarbons, presence of fractures etc) while production logging is here to maximise the production of an already-completed well through perforation services, plug setting and production fluid evaluation.

The recent developments of wireline tractors have allowed wireline to be used in highly deviated and horizontal wells, operations which historically have required coiled tubing or drillpipe-conveyed logging (TLC logging . These require a source of electrical power and so are always run on E-line. Tractors also enable wireline to expand into the operation of milling by being able to provide rotary motion.

(c) Wireline tools. A wireline tool string can be dozens of feet long with multiple separate tools installed

to perform multiple operations at once.

Directed Learning: Visit FMC Technologies website and download their brochure of their Lightweight Well Intervention Vessel and System. Go to www.FMCtechnologies.com. On the search engine of FMC put in Well . This will lead to a number of brochures that you can download.

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2.4 Subsea Well Workover 2.4.1 Types of Well Interventions There are in general three types of interventions: 1. Intervention due to mechanical failure 2. Intervention for remedial purposes 3. Intervention for data acquisition Types of Well Intervention Due to Mechanical Failure Subsea:

Replace tubing retrievable down hole safety valve. Replace wireline retrievable DHSV. Replace tubing. Replace packer. Replace tubing hanger dual-bore. Replace Xmas-tree dual-bore. Replace horizontal Xmas-tree.

Types of Well Intervention for Remedial Purposes Subsea:

Scale treatment: o Solvent wash. Perforating. Re-perforating. Acidising. Water block. Cement squeeze. Water shut-off. Install sand control.

Types of Well Intervention for Data Acquisition Subsea:

Various types of LOG for oxygen level, noise, water break through, visual camera and so on. Pressure and temperature surveys. Pressure transient surveys.

2.4.2 Equipment Required From a drill rig semi-submersible operated on anchor lines or on DP and from a drillship operated on DP, workover interventions are carried out with:

The workover/well completion riser for well with dual-bore trees. The full drilling riser with BOP at the seabed for heavy duty interventions, with a horizontal Xmas-tree type of completion.

The underwater deployment of both systems is costly in terms of rig/ship day rate and number of days for the job. If a DP WSV can be used, two systems can be deployed above the well:

The subsea lubricator with diver or ROV assistance for vertical or near vertical wells. The subsea lubricator with a lightweight riser allowing CT operations for deviated and horizontal wells.

The subsea lubricator and the coiled tubing systems are presented below.

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2.4.3 Subsea Well Servicing by Subsea Lubricator The use of this technique permits:

40 60% time saving when compared to a rig. Simplified planning and logistics. Rapid intervention on several wells in one field. Elimination of support vessels.

With a subsea wireline lubricator (SWL), the following well servicing tasks can be carried out:

All slickline and wireline operations (in vertical or near vertical wells). Logging and data acquisition. Perforating operations. Subsea well decommissioning.

Vessels The primary features of a well service vessel for this type of work are:

Classified to work with hydrocarbons on deck. First class station keeping provided by a fully redundant DP system and back-up. Excellent motion characteristics incorporating active and passive roll damping systems which give a highly stable platform for subsea operations. Purpose-built workover derrick over a 7 m x 5 m working moonpool. Well stimulation equipment comprising 4 x OPI 1,800 AWS HP pumps, integral tanks, filtration and transfer systems.

An example of a WSV is the seawell, previously owned by Stena Offshore, and now part of Cal Dive. Its capabilities are listed.

Figure 2.8

Workover Vessel Seawell Seawell is a well servicing vessel that has a long history of activities in the North Sea, performing more than 1,000 well intervention activities. View of the SWL (subsea well lubricator) shows the complete

system including the delivery tower on the vessel. Source Stena Offshore Vessel part of Cal Dive

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Figure 2.9

Range of Operations Performed by Lightweight Intervention Vessels (for example Seawell)

Source Azur Offshore Ltd

Figure 2.10

Light well Intervention Vessel Seawell Seawell entered service in 1987 as a diving support vessel but it is widely credited with pioneering

subsea light well intervention in the North Sea after completing its first well intervention project in 1988. In 1996 the Seawell performed what is thought to be the first ever installation of a replacement subsea

tree from a Dynamically Positioned mono-hull vessel anywhere in the world. In 1998 the Seawell completed the world's first ever wireline intervention on a horizontal subsea tree on Amoco Exploration's Arkwright Field in the North Sea. Currently owned by Helix Energy Solutions Group and operated by the

well intervention business unit, Helix Well Ops, the Seawell has entered more than 650 wells, decommissioned more than 150 live and suspended wells and 15 subsea fields.

Source Wikimedia Commons

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Technique Once on location and the Xmas tree has been prepared to accept the SWL, the system is fully tested then deployed via the moon pool using a deployment winch revved through the travelling compensator. The complete system once built up and tested is run in one piece and remains connected to the subsea Xmas tree for the duration of the work. In the event that an emergency disconnection is necessary, for either operational or environmental reasons, the guide wires are cut and the main control umbilical is remotely disconnected and recovered to the surface. Tool strings can be changed out simply without having to recover any portion of the lubricator and in many cases by only observing with the ROV. The lubricator hydraulic functions and Xmas tree functions are controlled via a dedicated umbilical which is deployed simultaneously with the lubricator. SWL System Components The SWL comprises the following major components:

Hydraulic removable stuffing box. Adaptor spool and lifting yoke. Lower and upper riser sections. Hydraulic tool trap. Subsea wireline BOPs hydraulic autolock. Cross over spool. Hydraulic actuator wireline cutting gate valve. Guideframe and frame spool. Crossover and wellhead connector. Crossover system. A self-contained and integral control system comprising: o Subsea lubricator actuators and components. o Locking and unlocking the subsea Xmas tree connectors. o Xmas tree functions. o Emergency disconnection of the system. o Testing of components. o Flushing and purging of the subsea lubricator. Umbilical and reel assembly. Liquid seal system.

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Figure 2.11

Lightweight Interventions Using a Subsea Wireline Lubricator (SWL) The SWL can be deployed on both types of Xmas trees. It has a landing package at the bottom. Above this there is the safety package which can close around or cut the wireline (a simple version of the full

drilling BOP functions). The long tubular strand above this is where the tooling for the downhole task is preloaded when it is on the vessel. At the top of this tubular strand there is the seal (a stuffing box)

through which the wireline passes. Source Stena Offshore

2.5 Development of Coiled Tubing Operations for Subsea Wells 2.5.1 From Drill Rig/Drillship/MODU Coiled Tubing Coiled tubing refers to metal piping, normally in diameter, used for interventions in oil and gas wells, which comes spooled on a large drum. The main benefits over wireline are the ability to pump chemicals through the coil and the ability to push it into the hole rather than relying on gravity. However, it consumes more space and offshore requires a larger and more robust rig, which can make it much more expensive on small platforms, which could support wireline but not coil, and subsea wells, where wireline can be run off a smaller and cheaper light intervention vessel. Onshore, they can be run using smaller service rigs and for light operations, the mobile self-contained coiled tubing rig. The tool string at the bottom of the coil is often called the bottom hole assembly (BHA). It can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations.

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Figure 2.12

Coiled Tube Workover Operations from a DP Vessel Downhole tooling delivered by a wireline can only be used where the well is vertical or mainly vertical

(that is loading using gravity). For horizontal wells it is necessary to use tractor devices, or more commonly coiled tubing (normally some diameter). The tensile strength of the coiled tubing can be

used to it along the horizontal well. In addition the fact that it is a tube means this can be used to carry fluids for cleaning or washing activities.

Source J E & P Associates 2.5.2 Uses Circulation The most popular use for coiled tubing is circulation. A hydrostatic head (a column of fluid in the well bore) may be inhibiting flow of formation fluids due to its weight (the well is said to have been killed). The safest (though not the cheapest) solution would be to attempt to circulate out the fluid using a gas, frequently nitrogen. By running in coiled tubing to the bottom of the hole and pumping in the gas, the kill fluid can be forced out to production. Circulating can also be used to clean out light debris, which may have accumulated in the hole. Pumping Pumping through coiled tubing can also be used for dispersing fluids to a specific location in the well such as for cementing perforations or performing chemical washes of downhole components such as sandscreens. In the former case, coiled tubing is particularly advantageous compared to simply pumping the cement from surface, as allowing it to flow through the entire completion could potentially damage important components, such as the downhole safety valve. Drilling A relatively modern drilling technique involves using coiled tubing instead of conventional drill pipe. This has the advantage of requiring less effort to trip in and out of the well (the coil can simply be run in and pulled out while drill string must be assembled and dismantled joint by joint while tripping in and out). Instead of rotating the drill bit by using a rotary table or top drive at the surface, it is turned by a downhole motor, powered by the motion of drilling fluid pumped from the surface.

44

Logging and Perforating These tasks are by default the realm of wireline. Because coiled tubing is rigid, it can be pushed into the well from the surface. This is an advantage over wireline, which is gravity dependent and depends on the weight of the toolstring to be lowered into the well. For highly deviated and horizontal wells, gravity may be insufficient. However, roller stem and tractors can often overcome this disadvantage at greatly reduced cost, particularly on small platforms and subsea wells where coiled tubing would require mobilising an expensive mobile drilling rig. The use of coiled tubing for these tasks is usually confined to occasions where it is already on site for another purpose, for example, using it for a logging run following a chemical wash.

Figure 2.13

Q4000

Q4000 is a unique multi-purpose oil field construction and intervention vessel commissioned in 1999 by Cal Dive International, and was built at the Keppel AmFELS shipyard in Brownsville, Texas. She is

operated by Helix Energy Solutions Group. Q4000 also has a unique column-stabilised semi-submersible design that combines dynamically

positioned station-keeping with a large deck space, significant deck load capacity and a high transit speed of 12 knots. The vessel provides a stable platform for a wide variety of tasks, including subsea

completion, decommissioning and coiled tubing deployment, and she is specifically designed for oil well intervention and construction in depths of up to 3048 meters of water.

Source Wikimedia Commons

45

3. NEW TECHNOLOGIES FOR SUBSEA PRODUCTION SYSTEMS

Figure 3.1

Worldwide Locations for Subsea Boosting/Separation Source IntecSea

3.1 Subsea Multiphase Pressure Boosting/Separation

Figure 3.2

Subsea Boosting or Processing Subsea pressure boosting options: (1) downhole with electrical submersible pumps; (2) gas lift in

production tubing; (3) seabed pump close to wells; and (4) seabed pump or gas lift at the riser base. Subsea separation: at well locations.

Source J E & P Associates

46

3.1.1 Why Subsea Boosting/Processing?

Reduce flowing pressure: o at wellhead: reserves. o in the flowlines, upstream the processing.

Reduce hydrate risk.

Reduction of water cut: o transport capacity used for hydrocarbons. o hydrate risks downstream the processing are reduced.

Pressure boosting: o transportation on longer distances. o reduction of flowlines diameter.

Solve topside problems of processing capacity.

Figure 3.3

Conventional Subsea Boosting Source Azur Offshore Ltd

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Figure 3.4

Conventional Subsea Separation Approaches

Source Azur Offshore Ltd 3.2 Subsea Multiphase Pumping When the pressure of a reservoir is such that it is insufficient to lift produced fluids to the surface, an artificial means is necessary to lift the fluids. is the general term for any means used to help lift production to the surface and can include methods such as injection of lift gas and downhole pumping. Alternatively, artificial lift can be viewed as a means of lowering the back pressure on the reservoir such that overall production volume can be increased. Pressure boosting, including multiphase pumping (subsea and topsides) can accomplish the same effect and since the wellhead pressure has been lowered, the reservoir is able to produce more fluids given the same drawdown. Pressure boosting can include:

Gas lift. Electric and hydraulic submersible pumps. Pressure boosting pump (seabed or topsides).

Subsea multiphase booster pumps add pressure energy to unprocessed well streams. They are an alternative to or complementary to other artificial lift techniques offering several new advantages. Typical areas are:

Draw down the wellhead pressure to increase production. A booster pump installed close to the wellhead can be used to draw down the wellhead pressure. The

effect on the well is a reduction in back pressure and the flow from the well will increase. Alternatively, the booster pump can be used to flow the same capacity in reduced pipeline diameter thus positively impact the flow assurance through increased velocity.

Calculations show that most wells can produce more oil than the natural flow allows, provided the wellhead pressure is lowered. This can be achieved by means of a subsea booster pump.

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Accelerate production with reduced production time. This is similar to the above.

Provide lift to wells with low natural production (low gas/oil ratio, high water cut, very deepwater). Some fields do not flow without artificial lift. This can be wells with low reservoir pressure/low GOR

combined with high API oil. Very deepwater with long risers gives high static back-pressure, sometimes in combination with high specific gravity of the fluid. Another application is in wells with high water production. Increase the flowline inlet pressure to enable long distance tie-back to existing or new production facility, or transport to shore.

On existing host facilities, tie-back of new wells (from a satellite field) requires the first stage separator pressure to be met by the new wells. Adequate inlet pressure on the topside separator may be prohibited by long distance pressure drop. A subsea booster pump located at the satellite field will increase the wellhead pressure and boosting the oil to flow with arrival pressures required from the processing plant. Increase the wellhead pressure to compensate for a drop in well production pressure.

In time, almost all wells experience a drop in production pressure. This is normally caused by a drop in reservoir pressure, or increased static resistance due to increased water cut. Subsea booster pumps may lift the pressure from selected wells and production can be maintained or increased. Increase the pressure from low pressure wells to balance the wellhead pressures

Subsea production facilities where oil is commingled sometimes experience unbalance in the production pressure from the different wells. The common solution has been to choke back the high-pressure producers. This is done to avoid throttle back (or even back-flow) of the low-pressure producers. If a booster pump is used to lift the pressure from the low-pressure producers, all wells can produce at a higher rate.

Figure 3.5

Subsea Performance Enhancements by Subsea Boosting or Processing

The aim of subsea boosting is to increase the field revenues. This may be by producing more oil from the reservoir (extending the production on its plateau level) or by increasing it at a faster rate (reducing the production time scale). The latter may be important with production to an FPSO. If the FPSO is rented the enhanced oil production rate may mean it is rented for seven years instead of for 10 years with oil

production at a slower rate. Source J E & P Associates

Subsea Boosting, Why?Enhanced and faster production

-Wellhead pressure draw-down -Compressor discharge pressure overcomes back-pressure and frictional losses

Increased Step-out Distance

Reduced OPEX

Reduced CAPEX

De-bottle-necking oil production

Development and production of low pressure reservoirs

Without SubseaBoosting

With SubeaBoosting

Increased Step-out Distance

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3.3 Systems 3.3.1 Multiphase Booster Pumps The development of multiphase pumps has followed one of two paths: 1. Hydrodynamic. 2. Positive displacement:

Rotating (screw). Piston.

Hydrodynamic Pumps One of the best known of the former type arises from the POSEIDON Research Project (started in 1984 by the IFP, Total and Statoil). The aim of the project was to select a pump design, which would be suitable for future subsea developments. After extensive analysis of the problems associated with the operational conditions and the different pump technologies, the helicon--axial principle was selected for the following advantages:

Capability to pump very high gas levels (in tests found to be up to 97% gas). Low sensitivity to abrasive suspended solid (no tight clearances) and corrosive fluids. Compactness, mechanical simplicity and reliability. Hydraulic self-regulation (adapting to suction flow and pressure fluctuations).

Figure 3.6

Multiphase Pumps Based on Helico-axial Turbine Type The production tubing brings oil from the oil layer. This will be as a single phase but with gas dissolved in the oil. By the time the oil reaches the seabed the pressure drop will mean that some of the gas will have come out of the solution that is a multiphase mix of oil and gas. Additionally over time the well will co-produce a certain amount of water and sand. This leads to a complex multiphase mix. Any pump arrangement must cope with this variable mix able to add pump energy to the mix and survive

against any potential damage by pumping such a mix. The first pumps shown to work are based on a helicon--axial turbine type. This is illustrated by the test

pump POSEIDON. Note it can pump any mix from 100% liquids to 100% gas. Also note that for significant pressure boosting it requires electrical power in the order of a few MWs.

Pumps of this type are offered by Sulzer and Framo. Source Framo Engineering

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Sulzer Pumps and Framo Engineering have been awarded licences based on the POSEIDON system. Total, together with Sulzer, have further developed the approach for a full subsea system (known as Nautilus). For a number of years such pumps have been operated at onshore fields and more recently topsides offshore. Another major development, specifically designed for subsea applications, is SMUBS system (Shell Multiphase Underwater Booster Station). This utilises the helico--axial principle for the pump. The key factor of the basic SMUBS concept is the use of an injection water driven hydraulic turbine as the power driver, thus avoiding the need for electrical power. It consists of a retrievable package encapsulated in a receiver barrel. The package is a cylindrical cartridge that includes, from the top down, the interface handling and locking mechanism, the suction flow mixer, the pump and the pump driver. The use of hydraulic power has the advantages of:

No electrical power lines No requirements for a wet electric high power connector No control systems (power is self-regulating).

The overall concept is best illustrated by operational location in the Draugen Field (Figure 3.7). Subsea Hydraulic SMUBS Pump for Shell Draugen Field Here an isolated satellite well is located in the vicinity of a water injection well some 6 km from the Draugen production platform. The water depth is 270 m. The system was installed in 1994 and was placed on a spare well slot on the water injection template. The drive fluid is the water injection water where some 45 bar pressure differential were taken out of the hydraulic power prior to injection into the reservoir. Operational results from late 1994 have shown the system boosts the well flow by some 6,000 bopd per day. Following the success of the basic concept, it has been further developed in an alternative form with a 2 MW electric power unit (termed ELSMUBS).

Figure 3.7

Draugen Field Pressure Boosting with Framo Pump An early demonstration of the helico-axial pump system was in the Shell Draugen Field in the North Sea using a Framo pump. In this case the pump is hydraulically driven, rather than electrically powered. In the field, injection water is carried to the pump location, and before being sent to the water injection tree it is passed through the turbine system. In the pump the water turbine shaft is connected to the

pumping turbine system. The use of this pumping arrangement to a satellite well increased its production rate from 6,000 bopd to some 11,000 bopd.

Source Framo Engineering

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Positive Displacement Pumps Examples of the screw type are the developments by:

Weir (Glasgow). Multiphase Systems. Bornemann and Leistritz.

The Bornemann two-screw pumps are self-priming, double-ended positive displacement pumps with external timing gears and bearings (see Figure 3.8).

Figure 3.8

Multiphase Pumps Based on Positive Displacement Twin-screw Type An alternative pumping system for complex multiphase mixtures is a twin-screw PD system. These were

initially developed by Bornemann in conjunction with Aker Solutions. Source Aker Solutions

All positive displacement pumps contain moving narrow sealing passageways. All these could be prone to wear, which would be accelerated by solids in the well fluids. Some advantages are:

High stability over all liquid gas fractions Can accommodate high inlet gas fractions.

However, in general the PD pumps are larger and heavier than the hydrodynamic types. Pumps of this type have been used in operational situations for land or platform locations, but have not yet been tested subsea. This type of pump is incorporated into the Kvaerner Eureka Subsea MultiBooster system. This development follows from the earlier Kvaerner work on the more complex Kvaerner Booster Station (KBS). The new system is more compact and based on standard guide post dimensions for easy installation and intervention. It was developed as part of the Norwegian initiative DEMO 2000.

52

Figure 3.9

Aker Solutions Subsea Multiboost General Specification The twin-screw PD pumping system is employed in the Aker Solutions multiboost pump tested as part of

the Norwegian DEMO 2000. Source Aker Solutions

Directed Learning: Search www.akersolutions.com for papers on Subsea Boosting and Subsea Separation to collect further information on their current projects and equipment. Search Google for other companies to add to your information.

Pump Location Subsea For multiphase pumping at a remote subsea development, the pump may be located either on the wellhead or on the manifold or template. The main difference with these options is the size of the pump. The wellhead pump handles the fluid from one well, whilst the pump on the manifold handles the fluid from a number of wells. One arrangement is for a wellhead pump mounted adjacent to the tree. This location is ideal since it ensures that the highest possible suction pressure is available thus reducing the gas fraction that the pump has to handle. With the bulk multiphase pump the configuration of the pump and manifold becomes more complex. In the case of the individual wellhead pumps, the pumps can be controlled to suit the flowing wellhead pressure and flow rate from the well. Also when a well is switched to the test flowline the configuration does not change with the test flowline having its own pump. This is not the case for the bulk multiphase pump where it will almost certainly be necessary to have both low pressure and high pressure headers in the manifold system. The reason for such an arrangement is to allow energetic wells to bypass the pump thus conserving the power required for pumping. Less energetic wells would flow into the low pressure header, all wells being choked to the flowing wellhead pressure of the weakest well, and then boosted into the high pressure header. Examples of seabed pumping systems are illustrated.

53

Figure 3.10

Examples of Subsea Boosting Projects Various early uses of subsea boosting schemes are represented and show their power levels.

Source Azur Offshore Ltd Subsea Electric SMUBS Pump for the BP ETAP (Eastern Trough Area Projects) Field The BP ETAP fields comprise five or six individual fields combined together. Unprocessed oil from the Machar Field flows through a 35 km line to the Marnock Central Processing Facility. The Machar Field will deliver some 30% of oil. The water depth is 86 m. The location and layout is shown in Figure 3.11. The two subsea multiphase booster pumps increase the production from the Machar Field by at least 4,000 bopd by adding 21.5 bar pressure to the unprocessed wellstream (after the initial flow phase). The pumps are powered by hydraulics, that being some of the energy from the water injection water which is pumped from Marnock to the Machar Field. The two pumps are installed 30 m downstream of production manifold. High pressure water from Marnock will power the pumps. Under normal operation, the full injection water flow rate of 65,000 bpd is routed through the two parallel turbine drives.

54

Figure 3.11

ETAP Field Pressure Boosting with Framo Pump The basis of the design of subsea boosting in the ETAP Field was the very long flowline from the Machar

Subsea Field to the processing platform Marnock, some 35 km away. The system proposed was the SMUBS system with the hydraulic power provided from the nearby water injection station.

The field was designed to receive this pumping system towards the end of its life in order to drive the multiphase mix the 35 km to the processing platform. In fact the field had sufficient residual pressure to

maintain the flow without the pump and so it was never deployed. Source Framo

Subsea Gas Boosting For gas fields, sooner or later the reservoir pressure becomes too low to maintain natural flow at a satisfactory production rate. Cost efficient solutions to boost the well-stream and regain satisfactory production rates will then be required. As a result of emerging subsea processing technology, subsea gas compression has matured as a field development element. The potential benefit of this technology is that it eliminates the need for surface production facilities and supports production from reservoirs otherwise not seen as economically attractive. Subsea gas compression solutions are associated with substantial technical challenges. Several key components are well known from surface production applications but need to be constructed differently to meet the special subsea requirements. Special engineering attention is needed to ensure the performance of the compressor and motor unit, the control and power distribution system, as well as other key process components such as for separation, cooling and pumping. All these elements are needed to successfully exploit the full potential of subsea gas compression. Also surface compression systems are relatively complex. When bringing this technology subsea it is even more important to focus on overall simplicity to ensure low cost and reliable operation.

BP - ETAP / MACHAR UK

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Several gas fields have been developed and designed as subsea to shore solutions, in spite of long distances to the processing facility. Some of the most profiled field developments are the Ormen Lange and the Snøhvit fields. The two are both developed solely as subsea to shore solutions without surface processing facilities offshore. Sooner or later such fields will need gas compression close to their wellheads. Subsea gas compression eliminates the need for a surface facility. Hence, the potential benefit for gas fields solely based on subsea technology is one of the main drivers for the development of subsea gas compression technologies. The second main application type is when gas is to be produced with tie-in to an existing host processing facility or pipeline with a different pressure level. Subsea gas compression could in such cases be used without any further need for modifications or pressure reduction of the existing infrastructure. Subsea gas compression is an emerging technology that can give great benefits as a field development tool. The economic potential and technical feasibilities are such that this technology should be attractive for any potential operator.

Figure 3.12

Subsea Gas Boosting

Early development work on seabed boosting was aimed at oil production. Later it was realised that gas fields would suffer from reservoir pressure losses in later life. Subsea gas boosting systems were then

developed. Source Aker Solutions

Some application areas are illustrated in Figure 3.13 below.

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Figure 3.13

Applications for Subsea Gas Boosting Examples of gas fields which will require gas boosting towards the end of their life are illustrated,

together with the timeframe of the required deployments. Source Aker Solutions

3.3.2 Partial Subsea Separation Pressure Boosting Systems One alternative to multiphase pumping is local subsea separation and the pumping of resulting single, or nearly single phase. Examples of hardware which illustrate the approach are the KBS and the Baker Jardine/Mentor Engineering VASPS. The Kvaerner system comprises three individual modules: separation, pump and compressor. The incoming fluid is separated into a gas and a liquid fraction which are respectively compressed and pumped by the integrated compressor and pump units. After pressure boosting, the gas and liquid streams can either be exported in separate pipelines or they can be recombined for multiphase transport to the processing facility. The system improves output from subsea wells since it enables production down to very low wellhead pressures and boosts the downstream pipeline flow. A full size KBS unit has been tested in simulated subsea conditions in Norway. An option might have been to carry out trials in Brazilian waters with the aim ultimately of extending its use to deepwater. Unfortunately no real trials have been carried out. The development experience has been utilised in further Kvaerner developments of a multiphase booster pump and separate subsea liquid pump (centrifugal pump) and a subsea gas booster (centrifugal compressor module).

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Figure 3.14

Early Subsea Separation/Boosting Systems An alternative to a pump type that can operate with a multiphase mixture is to carry out a subsea

separation and use a conventional pump on the separated liquid phase and a conventional gas compression turbine on the separated gas phase. The separate boosted streams could then be

recombined into a single flowline and carried separately in twin lines. Early examples of these are the Kvaerner Booster Station and the BOET System.

Source Azur Offshore Ltd VASPS (Vertical Annular Subsea Processing System) This is an integrated subsea separator and pump. Its geometry allows it to be installed within a 30-inch conductor in a dummy well. Liquid gas separation is achieved by arranging the inlet in a tangential manner such that within the body of the separator there is a hydrocyclone effect with the initially separated phases passing through a series of spiral separator joints, which perform secondary separation. In addition to gas and liquid phase outputs the equipment contains a sand cyclone for solids removal (dumping to a sump). Energy is added to the liquid phase by means of a down hole pump arrangement (see Figure 3.15).

Figure 3.15

Vertical Annulur Subsea Processing (VASP) System The VASP system deploys the principle of fluidics (a branch of engineering) to separate gas from the

liquids in a vertical system, and works like a simple hydrocyclone (no moving parts). Once the separation has taken place the liquid phase is boosted by a submersible pump.

Source J E & P Associates

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It is claimed that the use of VASPS could enable production over distances of 100 km and that well deliverables are significantly enhanced at increased water depths. Subsea VASPS Separator/Pump for Petrobras MARIMBA Field Trials A VASPS unit was manufactured under agreement by Cameron and after testing in a submerged tank supplied to Petrobras (as one of the active consortia members) was installed in the Marimba field as a part of the proving trial. The hardware designed for Marimba was based on the following main components:

Foundation. Flowbase. Multi-bore and single-bore flowline connectors. Separator composed of the pressure housing and the helix. Head assembly and top plug. ESP and liquid discharge tubing. Running tool.

The unit was installed in the Marimba field by SEDCO 710 in 395 m water depth, 550 m away from the MA-01 well subsea tree and 1,050 m from the P-8, where the gas and oil streams are sent. The unit started operation in July 2001. Before start-up of VASPS, well MA-01 was producing 750 m3 per day with gas-lift assistance of 100,000 m3 per day and with a flowing pressure of 36 kgf/cm2. Post start-up production has averaged about 1,000 m3 per day without gas lift assistance to MA-01. The effects the VASPS has had on the production rate and the reduction in gas lift volume is shown in Figure 3.16. This enhanced level of production has been maintained over many months. The VASPS system operated without problems and as such can be regarded as a viable system for other operations.

Figure 3.16

Test of VASP System in Brazil The VASP system was first field tested in the Marimba Field in Brazil, where it produced positive results.

Source J E & P Associates

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A version of this type of pumping system is used in the Perdido Field in deepwater in the Gulf of Mexico.

Figure 3.17

Vertical seabed pump system used in the Perdido Field in the Gulf of Mexico.

Source Shell plc 3.4 Full Subsea Separation The alternative to partial separation followed by boosting is to carry out a full separation (with equipment that in a very simple way mirrors conventional process facilities) with the purpose of producing fully stabilised end-products suitable for direct collection by a tanker or entry into existing, near located export pipeline systems. Full subsea separation developments have a significant history. These included paper studies, prototype test units under simulated conditions and full seabed tested units. The BOET system had the advantage of real subsea proving trials in the Hamilton Argyll Field towards the end of production from the field in 1989. The objective of the pilot unit project was to demonstrate that well fluids could be processed subsea to produce a dead crude suitable for loading directly into a tanker. Following systems commissioning some three months of operational trials were achieved. Problems with the control system ended the experiment. For illustration see Figure 3.18 below. 3.5 Other Seabed Processing 3.5.1 Subsea Separation and Re-injection of Produced Water An obvious extension of seabed separation is the re-injection of the produced water from the seabed. This offers a wide range of benefits. Most fields produce a lot more water than oil, some right from start-up. Taking out the water close to the wellhead greatly reduces the volume to be transported back to the host facilities, thus reducing both the transport and topside processing requirements.

SHELL PERDIDO FIELD Enhanced Vertical Deep WaterDual bore 10000psi XTree withFlow Module- Choke + Meter

NOVEL VERTICAL CAISSON SEPARATORduring final ASSEMBLY

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By directly re-injecting the water, the need for topside water injection facilities and associated flowlines is also reduced or eliminated. The process of subsea water separation reduces the back pressure on the production tree, thus enhancing the flow from the well. Again, the greatly reduced water content of the two-phase flow exported to the host facility diminishes the problems of hydrate formation. Troll Pilot This technology was tested in the Troll Pilot. The Troll Field is in the Norwegian trench about 70 km NW of Bergen. Gas is produced from the field to Troll A platform. Oil is being produced for the Troll B platform. Production from thin oil strata is routed to the Troll C platform. Troll C has a processing capacity of 20,000 to 30,000 tonnes of oil and 40,000 tonnes of water per day. Production is from subsea wells distributed between several subsea templates, each able to accommodate four wells. High water cuts occurred relatively soon after production starts. Therefore, a subsea separator (Troll Pilot) was installed in association with two subsea well templates connected in series. The object of Troll Pilot was to separate the bulk water from the well stream and re-inject this water from the subsea separator station. This station consisted of a separator, a water-injection pump and a water-injection well with associated Xmas tree, all incorporated in a structure that is separate from the subsea well templates. It was operated for a period of several years and provided important operations proof of concept data.

Figure 3.18

Troll Pilot Test for Water Separation and Re-injection on the Seabed Seabed separation of water from the well fluids, with re-injection of the water back to the formation, was tested in the Troll Pilot at the Norwegian field. The system comprises the separator vessel and controls,

a water injection pump and a water injection tree. Test results are provided. Source ABB

An existing system is that of FLEX-SEP by Aker Solutions (Figure 3.19 below).

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Figure 3.19

Flex-Sep System Design Seabed water separation and re-injection units are available from suppliers. The Flex-Sep system offered

by Aker Solutions is illustrated. Source Aker Solutions

3.5.2 Seabed Raw Water Injection The possibility of raw (aerobic) seawater injection, using seabed mounted equipment, could have a major impact on the CAPEX and OPEX of water injection requirements. Processing Joint Industry (JIP) studies are being carried out to investigate such possibilities, the facilities and the operational requirements. A number of schemes providing pumping, filtration/solids settlement, Bernoulli strainers and electro-chlorination are being explored.

Figure 3.20

Raw Water Seabed Injection Sea Boost Normally water for water injection if lifted from below the production host, treated on the host (filtration,

chlorination and oxygen removed) prior to the injection into the appropriate wells using massive host based pumps. This involves the installation of large lengths of water flowlines on the seabed.

In raw water seabed injection schemes the seawater is treated on the seabed and pumped directly to the reservoir by seabed-based pumps. A system offered by Aker Solutions is illustrated.

Source Aker Solutions

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3.6 Subsea Electrical Power Distribution Most boosting and processing systems, discussed above, utilise high power electric motors (that is several hundred kilowatts). Therefore, one of the problems they face is the provision of electrical power at their point of operation, which in many cases could be at remote wellhead locations. The actual power levels, and the distance(s) from the generation source (assumed to be on a host platform or floater), will vary. On land it is common for power to be delivered to required fixed, multiple locations either by individual lines to each item of equipment or a single line to a local distribution centre with individual lines thereon. Also for high power requirements it would be common to transmit the initial load at high voltage and transform down to the local voltage at the distribution centre. Such alternatives are possible with subsea power. These are now available as proven systems.

Figure 3.21

Subsea Power Distribution Systems Most of the seabed boosting and separation schemes require the availability of large amounts of electrical power. Subsea power transmission equipment (based on land-based power transmission) was designed

and tested in underwater trials. Such equipment is now operationally available as illustrated. Source Azur Offshore Ltd

3.7 Recent Headline Field Utilising New Technologies 3.7.1 King Field, Gulf of Mexico (BP) Subsea boosting technology is used to increase production in the King Field, Gulf of Mexico. The field is located at a water depth of 1,700 m, and lies 29 km from the host platform, making it one of the longest booster subsea tie-backs to date. King Field Development King is one of the three fields producing from the Marlin TLP and represents more than half of Marlin TLP production. The complex lies 18 miles from Marlin in the Viosca Knoll area, approximately 150 km southeast of New Orleans. In late 2007, the project to retrofit two existing subsea wells with the innovative subsea booster pump to optimise oil recovery commenced and operated successfully.

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Figure 3.22

Field Examples Deepwater Boosting in King Field (GoM)

Source Aker Solutions

Figure 3.23

King Field Details of Seabed Pump

Source Aker Solutions

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King Field Subsea Pumping Contract and Power Umbilical Contract The contract to supply the pumping system was won by Aker Kvaerner Subsea. In total, Aker Kvaerner supplied three systems (for two subsea pump stations plus one spare) at a total value of NOK220 million. The total contract included modules with manifolds, variable speed drives, topside and subsea control systems, topside lube oil and hydraulic power units, and high voltage connectors and jumpers. The pump station systems were manufactured at Aker Kvaerner facility in Tranby, Norway. The booster assembly consisted of a manifold base skid supporting the pump module itself. Each of the 70 t assemblies were located over 3.6 m diameter suction piles. The design specified MPC-335-50 Bornemann pumps, which can pump at 75,000 bpd and give a 50 bar differential pressure. Inlet pressures at the King wells range from 48 bar to 127 bar. The industrial cable supplier Nexans was awarded the $15 million contract for the design and manufacture of the first subsea service umbilical that integrates a high-voltage (HV) cable rather than having to resort to separate umbilical and power cables. The deepwater 16-mile-long power umbilical consisted of a main dynamic and an infield umbilical. Apart from low- and high-voltage electrical power, the umbilical also provides oil for the pump lubrication, chemicals for injection to prohibit the formation of hydrates and fibre-optic communications. The conductor to the booster system carries 24,000 V. 3.7.2 Ormen Lange Gas Field, Norway (StatoilHydro) The Ormen Lange gas field, located 120 km west-northwest of Kristiansund, was developed as a subsea tie-back to shore. The initial development consisted of two templates. Each template connected to two pipelines transporting the gas to the shore terminal. The shore terminal is located at Nyhamna, on the island of Gossen close to Molde. The processed gas is exported through a new 1,200 km long pipeline to the UK market.

Figure 3.24

Field Example Subsea Gas Compression for Future Deployment in the Ormen Lange Field

(Norway) Source Aker Solutions

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For the initial production phase, gas from Ormen Lange flowed to Nyhamna by means of reservoir pressure. Later in the production phase, offshore compression was required in order to maintain the production level and to recover the anticipated gas and condensate volumes. Base case option was subsea compression. The permanent subsea compression station was installed at a depth of 860 m, utilising electrical power from shore. The permanent long step-out power supply transports the required electrical power and the control signals from shore and 120 km to the subsea compression station at Ormen Lange.

Figure 3.25

Ormen Lange Seabed Compression Pilot Source Aker Solutions

To follow the subsea compression option required a pilot study of the technology. Aker Solutions was selected to engineer, procure and construct a full-size subsea compression station pilot, and Vetco Aibel AS was selected to engineer, procure and construct a long step-out power supply pilot. After delivery, the two pilots were tested for two years at the Ormen Lange gas treatment facility at Nyhamna to qualify the subsea compression technology for commercial use. The subsea compression pilot represents one of the four compressor trains required for permanent subsea compression of the Ormen Lange Field. The long step-out power supply pilot represents the equipment required to supply electrical power and control signals to the permanent subsea compressor station some 120 km from shore.

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Figure 3.26

Ormen Lange Nyhamna Test Facilities Source Aker Solutions

On the Ormen Lange pilot programme, the value of subsea compression station pilot contract was approximately NOK850 million. The contract also included an option to supply equipment for the permanent subsea compression station. The value of the long step-out power supply pilot contract was approximately NOK97 million. The contract also included an option to supply the permanent long step-out power supply system. 3.7.3 Tyrihans Field Tie-back, Norway (Statoil) The Tyrihans oil/gas/condensate field is located in the Norwegian Sea off mid-Norway. The production templates for the field include subsea wells tied back to the Kristin floating production platform. In the plan for development and operation (PDO) output from the field was estimated at 182 MMbbl of liquids, comprising both oil and condensate, and 34.8 bcm (1229 tcf) of gas. Statoil, which was targeting 55% recovery from its Norwegian subsea fields, has brought the full range of improved recovery techniques to bear on Tyrihans. These include multilateral wells, downhole integrated fibre-optic systems, remote operation of subsea wells and facilities with the backing of onshore support, subsea injection of raw seawater, direct electrical heating of the production pipeline, and possibly subsea compression in the tail-end phase. Subsea Injection of Raw Seawater Water injection has brought the benefits of stabilising the oil zone in the southern reservoir and of equalising the pressure difference between the two reservoirs. Raw seawater was injected through a seabed pumping station. This was the first time Statoil had used this new technology and only the second application of such a system. The injection station consists of a standard FMC template housing a manifold, a pump cassette with two pumps supplied by Aker Solutions, and the injection well. With the two pumps running in parallel, the design injection capacity is 88,000 b/d of oil, but Statoil achieved up to 100,000 b/d. This primarily depended on reservoir properties and how much power was lost in transmission.

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Power is supplied from Kristin at 2.5 MW to each pump and stepped down on the field from 22 kV to 6.6 kV the first time Statoil had used subsea transformers. The Tyrihans project has been co-ordinated closely with the Tordis project for subsea water separation and injection. The critical component for the Tyrihans subsea water injection system is the electrical couplers. It is essential to prevent the ingress of seawater into the pump motors and the electrical system. A careful choice also had to be made on the materials for the pump components that were in contact with seawater. Before injection, the seawater passes through a filtration system to remove extraneous objects. By avoiding the need for a pipeline from the host platform and for accommodating the pump on the platform, the subsea solution provides savings in the order of $35 million to $50 million. Water injection started in 2010. The water injection station and template were installed in 2009.

Figure 3.27

Field Example Subsea Raw Water Injection System in Tyrihans Field (Norway)

Source Aker Solutions

Directed Learning: Download the FMC Technologies brochure on Subsea Processing from their website www.fmctechnologies.com. Also go to www.google.com Look for TYRIHANS SRSWI to find more information. Also look at other Google references. Add this information to your file.

3.7.4 TORDIS IOR Project Norway (Statoil) FMC Technologies is the second main developer of subsea boosting and separation equipment, with current projects around the world including the Tordis IOR Project.

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Figure 3.28

FMC Subsea Processing Projects

Source FMC Technologies Tordis is located in block 34/7 of the Tampen area in the Norwegian North Sea. It came on-stream in 1994. In addition to the main Tordis structure, the development embraces the Tordis East (1998), Borg (1999) and Tordis South East (2001) fields. These discoveries have all been developed with subsea installations tied-back to the Gullfaks C platform 10 km away for processing, storage and export. After the main Tordis manifold was installed to receive seven satellite wells, templates J (production) and K (injection) were installed. The field currently has nine producing wells, originally producing 24,000 bpd but falling back to 12,000 bpd along with six injectors to maintain reservoir pressure.

Figure 3.29

Field Example Tordis Subsea Separation Boosting and Injection

Source FMC Technologies

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IOR Operations In December 2005, Statoil received government approval for its Improved Oil Recovery (IOR) project. It awarded the NOK625 million contract to Kongsberg FMC for a subsea separation station. Acergy won the NOK200 million contract for marine operations while Saipem lifted the separation station into place under a NOK50 million contract. Statoil expects to improve the recovery factor from 49% to 55% or around 35 million barrels of oil, accounting for approximately 19 million barrels of the oil recovery.

Figure 3.30

Details of Tordis Separation System

Source FMC Technologies This is achieved by removing water from the well stream and re-injecting it in a separate well, thereby reducing the back pressure towards the Tordis field and allowing more hydrocarbons to be processed at Gullfaks C. The well fluid is first routed into the separation tank to remove the gas. The remaining water, oil and gas are separated through gravity. The water is pumped via a water injection pump directly back into the Utsira reservoir through a 12-inch ball valve Xmas tree. Pumping and Separation Systems The water injection pump is a standard Framo pump system which is driven by an electrical motor powered through an electrical power cable from the Gullfaks C platform. The pump can be retrieved for maintenance by a separate pump running tool. Oil and gas are remixed and pumped through a standard Framo multiphase pump back to the Gullfaks C platform. System Description:

Pipeline Inline Manifold (PLIM) The PLIM was installed in summer 2006 to interconnect the flowlines from the Tordis subsea manifold

to the Gullfaks C platform allowing re-routing of the Tordis well stream to Gullfaks C via the subsea separation station. The PLIM allows full bypass of the Tordis subsea separation, and was installed during a planned maintenance shut-down of the Gullfaks C platform.

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Water Injection Tree The water injection tree is a simple Xmas tree consisting of a ball valve. A conventional internal

tree cap is installed in the vertical entry section of the tree allowing for workover of the well. The re-injected water is pumped through this Xmas tree through a casing direct into the Utsira water reservoir. This is a non-hydrocarbon reservoir with ambient pressure.

Subsea Separation Boosting and Injection (SSBI) Station

The subsea separation station separates the water from the well stream which is re-injected through the large bore water injection tree. After separation, gas and oil are mixed and pumped via a multiphase pump back to the Gullfaks C platform. The SSBI station was installed in October 2007.

The separation station contains the following main elements: Foundation Structure and Manifold The Tordis SSBI station has an independent conventional, over-trawlable foundation structure supporting the manifold, the separation module and all other components. The structure has four suction anchors, one in each corner for foundation and levelling. The manifold module provides connection to the flowlines via a Rovcon connection system and interconnects the various modules. The estimated installed weight of the subsea separation station with manifolds and separation modules is approximately 900 tonnes. Separation Module The well fluid from the Tordis Field is first routed into the separation tank. The inlet cyclone separator in the tank does a first separation where the majority of the gas is separated out and routed through a separate pipe outside of the tank, thereby minimising the size of the separation tank. The remaining water, oil and gas are separated through the gravity principle inside the tank. The water is the heaviest part which is pumped via a water injection pump directly back into the Utsira reservoir through the Xmas tree. Oil and gas are remixed and pumped through a multiphase pump back to the Gullfaks C platform. Any deposit of sand inside the separation tank is handled by the sand removal system. The separation module is retrievable as a separate unit. Sand Removal System Any sand from the well stream will deposit at the bottom of the separation tank. A flushing system with specially designed nozzles has been developed to flush out the sand at certain intervals. The sand is transported into the Desander Module where it can be remixed with the injection water and re-injected into the reservoir downstream of the water injection pump. Alternatively the sand can be remixed with the oil and gas flow and pumped back to the Gullfaks C platform. Water Injection Pump The water injection pump is a standard Framo pump system which is driven by an electrical motor powered through an electrical power cable from the Gullfaks C platform. The pump can be retrieved for maintenance by a separate pump running tool. Multiphase Pump The multiphase pump is a standard Framo pump, similar to the water injection pump, and is powered through an electrical power cable from the Gullfaks C platform. It can also be retrieved by a separate pump running tool. Other The subsea separation station is equipped with two multiphase flow meters (Roxar) which will measure the composition of the well flow to prepare the separation system settings. A level monitoring system is installed in the separation tank to monitor water, oil and gas interfaces which again provide input to the water pump speed and the multiphase pump speed. The subsea separation station includes one subsea control module with 51 functions to control the various functions of the station and communicate back to the Gullfaks C platform.

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Directed Learning: Visit the Statoil website (www.statoil.com) and search for information on Tordis. Look for the animation which gives more information about the field and the use of the subsea separator to improve field productivity.

3.7.5 Marlim Field, Campos Basin Brazil (Petrobras) Marlim is largest field in the Campos Basin, located 70 miles (110 km) offshore of Brazil, at water depths ranging from 2,100 to 8,500 feet (650 to 2,600 m). It was once considered the largest subsea development, with 129 wells and eight floating production units (FPU), devoted to the extraction of oil and gas. Today, as this mature field approaches 20 years in operation, the field is producing an increasing amount of water, which is limiting the oil handling capacity of the surface facilities; and sand, which has the potential for damaging the overall system. FMC was selected to supply a subsea separation and pumping system for the Marlim field, which has been in operation since 1991. The main purpose of the system is to debottleneck the floating production facility and increase production by removing unwanted water from the production stream, at the seabed. This system will also be the first to use water re-injection to increase reservoir pressure and boost production. The subsea separation, pumping and water re-injection system, developed by Petrobras and FMC, was installed at a water depth of 2,950 feet (900 m) and answered the challenges of maturing fields. The system receives the production stream, which contains a mixture of oil, gas, water and sand, and first separates the gas from the liquids. Then, the heavy oil is separated from the water, using a novel pipe separation design that was licensed and developed in co-operation with Statoil. The system also integrates proprietary water treatment and sand handling technologies as part of the subsea separation system. The separated gas is added back to the oil stream to aid its lifting to the FPU, while the separated water is pumped back into the reservoir to further increase production. The unique design of the Marlim subsea separation system accomplished a number of firsts in the industry, specifically:

the use of subsea separation in a deepwater, mature field environment re-injection of water into a production reservoir, and separation of heavy oil in a subsea environment.

The equipment was jointly engineered between operations in Brazil, Norway and The Netherlands. Final manufacturing and integration activities were performed at the Rio de Janeiro facility, and began operation in 2011. The contract was valued at approximately $90 million.

Figure 3.31

Field Example Marlim Field Subsea Processing (Campos Basin Brazil)

Source FMC Technologies

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Figure 3.32 Details of Subsea Processing System for Marlim Field

Source FMC Technologies 3.7.6 Pazflor Field Development, Angola (Total) Pazflor is located in deepwater offshore Angola Block 17, 150 km (93 miles) off the coast of Angola and 40 km (25 miles) north-east of Dalia. It lies in water depths of 600 1,200 m (1,968 3,907 ft). The development extends over 600 km² with a north-to-south axis of more than 30 km. Pazflor includes the Perpetua, Acacia, Zinia and Hortensia Fields, which lie in the eastern portion of Block 17. Pazflor Reservoirs The project targeted development of hydrocarbons is in two independent reservoir structures.

Figure 3.33

Field Example Subsea Separation for Pazflor Fields (Angola) The Pazflor Field development was the third main development in the Total Block 17, Angola. The first

two were of single large reservoirs (Girassol and Dalia). To provide the production size of some 220,000 bopd, the Pazflor Field systems combined production from five separate reservoirs.

Source Azur Offshore Ltd

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Figure 3.34

Pazflor Reservoirs Information

The five reservoirs contain two very different oil types (API gravity, GOR, reservoir temperatures and pressure). The differences are illustrated. They require different production and processing parameters.

Source Azur Offshore Ltd The Oligocene reservoirs are located in water depths from 1,000 m to 1,200 m. They contain light oil of around 35° 38° API and is developed using a production loop including riser bottom gas lift. The Miocene reservoirs, in 600 900 m waters, contain heavy oil of around 17° 22° API, which is recovered using subsea gas/liquid separation and liquid boosting. This system was supplied by FMC.

Figure 3.35

Pazflor Field Subsea Development Strategy The much heavier and more difficult flowing Miocene oil has seabed separation and boosting equipment,

whereas the lighter, easier flowing Oligocene oil does not. Source Azur Offshore Ltd

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The overall development includes 49 subsea wells connected via subsea production, injection lines and risers to a spread-moored FPSO. The topside control system is designed to accommodate a further 21 wells and a fourth subsea separation unit. These subsea wells are connected via subsea production, injection lines and risers to a spread-moored FPSO. There are three subsea separation systems provided by FMC following the success on Tordis. The main difference between the two is that separation modules are vertical and not horizontal, which provides a smaller footprint.

Figure 3.36

Pazflor Subsea Separation Units

The subsea separators, supplied by FMC Technologies, deploy vertical separation tanks. Source FMC Technologies.

Further Research: Go to the Shell website (www.shell.com). Go to Home > About Shell > Our strategy > Our major projects > Parque das Conchas (BC-10). Explore the information and videos about this project.