Safety and Reliability Assessment of All-Electric Subsea

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Jon Anders Søberg LindstadSafety and Reliability Assessment of All-Electric Subsea NTNU Norwegian University of Science and Technology Faculty of Engineering Department of Mechanical and Industrial Engineering

Master ’s thesis

Jon Anders Søberg Lindstad

Safety and Reliability Assessment of All-Electric Subsea

Master’s thesis in Subsea Technology June 2020

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Jon Anders Søberg Lindstad

Safety and Reliability Assessment of All-Electric Subsea

Master’s thesis in Subsea Technology Supervisor: Jørn Vatn

June 2020

Norwegian University of Science and Technology Faculty of Engineering

Department of Mechanical and Industrial Engineering

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Preface

This Master Thesis was carried out during the spring of 2020, and it represents the finalization of the two-year Master of Science program in Subsea Technology at the Norwegian University of Science and Technology (NTNU) in Trondheim, Norway. The master thesis in RAMS is written at the Department of Mechanical and Industrial Engineering.

It is presumed that the reader is familiar with Reliability, Availability, Maintainability and Safety (RAMS) - engineering. It is also presumed that the reader has basic knowledge about the petroleum industry, but it is not a prerequisite.

Trondheim, 09.06.2020

Jon Anders Søberg Lindstad

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Acknowledgement

First, I will like to thank Professor Jørn Vatn in the RAMS group, my supervisor at NTNU for his guidance and support during this master thesis project.

Second, I will like to thank Professor Mary Ann Lundteigen at the department of Engineering Cybernetics at NTNU for valuable input to my master thesis.

Third, I will like to thank the SUBPRO organization for:

• Attendance to a seminar about an All-Electric Subsea Production System,

• Gaining access to the 2019 conference proceedings from the Underwater Technology Conference (UTC) in Bergen, Norway.

Fourth, I will like to thank Professor Markus Glaser from Aalen University in Germany for conversations through email about all-electric subsea, including suggestions about relevant papers. Fifth, I will like to thank PhD student Ewa Laskowska in the RAMS-group at NTNU for valuable discussions and input.

My special thanks goes to my family and friends for valuable discussions and input throughout this thesis work.

J.A.S.L

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Executive Summary

Subsea production refers to wells located on the seabed, and associated equipment and modules to produce hydrocarbons. The most common system for subsea production control is an electro- hydraulic system. The next technological step implies going fully electric, which the petroleum industry has acknowledged due to technical, economical and health, safety & environmental reasons.

Prior to implementing all-electric, the technology has to be qualified, which is challenging, especially in Norway due to its strict regulations. One of the reasons is that current standards and guidelines give directions based on the electro-hydraulic system, so for all-electric subsea wells to be qualified and verified, standards and guidelines must be updated. How to isolate an all-electric subsea well in the case of an emergency, is one of the important topics that needs to be covered.

My analysis of an all-electric system and technology has accordingly aimed to contribute to the technology qualification of all-electric subsea wells. My toolbox and theoretical background for performing this analysis has been reliability, availability, maintainability and safety – evaluations (RAMS). In this thesis, failure modes, effects and criticality analysis (FMECA) has been used as a tool to compare the electro-hydraulic system with the all-electric system for the subsea Christmas tree. Two “single point of failures” was identified for the electro-hydraulic system. Both of these were on the hydraulic return side of the valve actuator. Given normal production, the occurrence of either of these will prevent well isolation. The benefit associated with electro-hydraulic control is the mechanical fail-safe-close of valves by spring-return. For the all-electric system all the valve actuators depend on the same power supply for fulfilling the safety function. A clear advantage with the all-electric system is that the system provides feedback for the safety function.

To summarize, this thesis work has aimed at contributing to the technology qualification process of going all-electric subsea. This has been approached by reviewing qualification of subsea systems, fail-safe principles for valve actuators, and by visualizing system knowledge required for well isolation of an all-electric subsea well.

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Sammendrag

Undervannsproduksjon refererer til brønner som ligger på havbunnen, og tilhørende utstyr og moduler for å produsere hydrokarboner. Det vanligste systemet for kontroll av undervannsproduksjon er et elektrohydraulisk system. Det neste teknologiske trinnet innebærer et hel-elektrisk system. Petroleumsindustrien har anerkjent dette på grunn av tekniske, økonomiske og helse, miljø & sikkerhets hensyn.

Før implementering av et hel-elektrisk system må teknologien kvalifiseres, noe som er utfordrende, spesielt i Norge på grunn av et strengt regelverk. En av grunnene er at gjeldende standarder og retningslinjer gir instruksjoner basert på det elektrohydrauliske systemet. For at hel-elektriske undervannsbrønner skal bli kvalifisert og verifisert, må standarder og retningslinjer oppdateres. Hvordan en hel-elektrisk undervannsbrønn kan isoleres i et nødstilfelle, er et av flere viktige temaer som må avklares.

Min analyse av et hel-elektrisk system og elektrisk teknologi, har derfor hatt som mål å bidra til teknologikvalifiseringen av hel-elektriske undervannsbrønner. Min verktøykasse og teoretiske bakgrunn for å utføre denne analysen har vært pålitelighet, tilgjengelighet, vedlikeholdsvennlighet og sikkerhets (RAMS) – evalueringer. I denne masteroppgaven er feilmode- og feileffektsanalyse (FMECA) brukt som et verktøy for å sammenligne det elektrohydrauliske systemet med det hel-elektriske systemet for et undervanns ventiltre (såkalt

”juletre”). To “enkelt-punkt feil” ble identifisert for det elektrohydrauliske systemet. Begge disse var på hydraulikk-retur siden av ventilaktuatoren. Fordelen forbundet med elektrohydraulisk styring er en mekanisk sikkerhetsmekanisme som stenger ventilene ved hjelp av fjærretur. I det hel-elektriske systemet er alle ventilaktuatorene avhengig av den samme strømforsyningen for å oppfylle sikkerhetsfunksjonen. En klar fordel med det elektriske systemet er at systemet gir tilbakemelding om gjennomføring av sikkerhetsfunksjonen.

For å oppsummere, denne masteroppgaven har hatt som mål å bidra til teknologikvalifiseringsprosessen for overgangen til et hel-elektrisk system for undervannsproduksjon. Dette har blitt gjort ved å gjennomgå kvalifisering av undervannssystemer, sikkerhetsprinsipper for ventilaktuatorer, og ved å visualisere systemkunnskap som kreves for brønnisolering av en hel-elektrisk undervannsbrønn.

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List of Figures

Figure 1 Dual bore vertical XT ... 10

Figure 2 Unbalanced valve with spring and hydraulic actuator (valve is open) ... 12

Figure 3 Electro-hydraulic control system ... 14

Figure 4 Step-wise approach of SPS electrification – Based on Melbø (2019) ... 19

Figure 5 All-electric control system ... 21

Figure 6 Redundant battery channels (centrally located) ... 22

Figure 7 Johan Sverdrup platforms - Courtesy Equinor ASA ... 25

Figure 8 Subsea production by FPSO – Courtesy Aker BP ... 26

Figure 9 Ormen Lange - Courtesy A/S Norske Shell... 26

Figure 10 XT which produced at Ekofisk - Courtesy Jan A Tjemsland ... 27

Figure 11 Bow tie for subsea barrier management – Based on Ersdal (2014) ... 30

Figure 12 Subsea XT- and downhole-barriers ... 31

Figure 13 Failure mode classification – based on Rausand and Høyland (2004) ... 33

Figure 14 Proof test classification - based on Rausand (2014) ... 35

Figure 15 Relation between PFD, proof tests and SIL – based on Vatn (2019) ... 38

Figure 16 Illustration of a XT for isolation of one subsea well ... 40

Figure 17 Technology qualification process - adapted from DNV-RP-A203 (2011) ... 42

Figure 18 Multiphase Markov model – based on Laskowska and Vatn (2019) ... 48

Figure 19 Electro-hydraulic valve actuation - Courtesy Glaser (2019) ... 50

Figure 20 Gate valve electric actuator - Courtesy Schwerdtfeger et al. (2017) ... 52

Figure 21 Spring-based electric valve actuator - Courtesy Moe et. al (2018) ... 52

Figure 22 Battery-based electric valve actuator – Courtesy Glaser (2019) ... 53

Figure 23 System architecture for all-electric XT actuation (ISSA project) ... 54

Figure 24 System breakdown structure for the electro-hydraulic system ... 67

Figure 25 System breakdown structure for the all-electric system ... 70

Figure 26 Illustration of isolation of one all-electric subsea well ... 75

Figure 27 Most likely scenario in the near future ... 90

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List of Tables

Table 1 Drivers for all-electric ... 17

Table 2 Relevant standards and guidelines for subsea production systems ... 23

Table 3 Relevant standards and guidelines for reliability and safety ... 29

Table 4 Safety integrity levels – low demand mode ... 37

Table 5 Technology categorization ... 43

Table 6 FMECA – common columns ... 46

Table 7 Hydraulic versus electric actuation technology subsea ... 49

Table 8 Available data in an electric valve actuation system ... 55

Table 9 Condition monitoring in different operating phases ... 58

Table 10 Advantages and disadvantages with PST ... 59

Table 11 Classification of failure rates and severity ... 65

Table 12 Description of equipment (electro-hydraulic) ... 67

Table 13 Framework for the FMECA (electro-hydraulic) ... 69

Table 14 Description of equipment (all-electric) ... 71

Table 15 Framework for the FMECA (all-electric) ... 72

Table 16 Safety summary for the electro-hydraulic analysis ... 76

Table 17 Safety summary for the all-electric analysis ... 78

Abbreviations

AMV AWV CAPEX DC DCV DHSV EH-MUX EPC EPU ESD FMECA FPSO FTA

Annulus Master Valve Annulus Wing Valve Capital Expenditures Diagnostic Coverage Directional Control Valve Downhole Safety Valve

Electro-Hydraulic (Multiplexed)

Engineering, Procurement and Construction Electrical Power Unit

Emergency Shutdown

Failure Modes, Effects and Criticality Analysis Floating Production, Storage and Offloading vessel Fault Tree Analysis

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ix HPU

HSE HP LP NPV OPEX PFD PFDavg PMV PST PWV RAMS ROV RP RUL SCM SEM SCS SCSSV SIF SIL SIS SPS XOV XT

Hydraulic Power Unit

Health, Safety and Environment High Pressure

Low Pressure Net Present Value

Operational Expenditures

Probability of Failure on Demand

Average Probability of Failure on Demand Production Master Valve

Partial Stroke Testing Production Wing Valve

Reliability, Availability, Maintainability and Safety Remotely Operated Vehicle

Recommended Practice Remaining Useful Life Subsea Control Module Subsea Electronics Module Subsea Control System

Surface Controlled Sub-Surface Safety Valve Safety Instrumented Function

Safety Integrity Level Safety Instrumented System Subsea Production System Cross-Over Valve

Christmas (X-Mas) Tree

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1.1 Background

Subsea production refers to wells located on the seabed, and associated equipment and modules for distributing the produced well flows. Subsea production systems (SPS) are utilized in three development concepts:

• Tie-in of subsea wells to a fixed platform structure,

• Floating offshore structure connected to subsea wells,

• “Subsea-to-shore”, which is a concept without an offshore structure.

The most common system for subea production control is an electro-hydraulic system, where the hydraulic-and electrical-power is distributed to the subsea equipment by the means of an umbilical. The next technological step implies going fully electric. Electric control of subsea wells was first explored in the early 1990s (Sangesland et al., 1992; Jernström et al., 1993).

Today, Total is at the forefront of this development, launching the world’s first all-electric subsea pilot well, K5F3 in august 2016 (Total, 2016a).

New oil & gas discoveries are often located at: ultra-deep waters, i.e. exceeding 2000m depth;

further offshore than conventional fields; and remote areas like the Arctic. Developing and operating subsea fields at such locations requires technological improvements (Abicht et al., 2017; IEA, 2013; Imle et al., 2019). The current electro-hydraulic system has technical limitations, because:

• When the distances increases; charging subsea accumulators to operational pressure becomes time consuming.

• At larger sea depths the hydrostatic pressure limits the design of the electro-hydraulic system, partly due to increasing size of spring modules within gate valves.

• The efficiency of energy storage within subsea accumulators decreases with water depth, which results in larger accumulator modules (Umofia, 2014).

Production availability (uptime) for fields involving subsea wells on the Norwegian continental shelf (NCS)1 typically ranges between 80-91% on a yearly basis. A North Sea case study

1 Based on publicly available data for production availability (uptime) found in annual reports and quarterly presentations. The availability range is based on a selection of fields: Balder, Draugen, Gjøa and Goliat in year 2018 and 2019.

1 Introduction

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3 showed that hydraulic distribution systems contributed to 37% of the production availability loss (Melbø, 2019). This is not necessarily representative for all operating fields on the NCS, but it is a key indicator that the electro-hydraulic system can have a significant impact on the production uptime. Considering the availability range given above, the electro-hydraulic systems could potentially account for 12-27 days of downtime throughout a year.

The drivers for all-electric can be categorized as technical, economical and HSE. The technical drivers are improved operational characteristics and simplification of the SPS. The economical drivers are reduced costs with regards to both capital expenditures (CAPEX) and operational expenditures (OPEX), in addition to reduced downtime. Removing the hydraulic systems is also motivated by HSE, as it will result in zero-discharge and zero-leakages of hydraulic control fluid to the environment. This is important in vulnerable areas where future oil & gas fields are anticipated to be subject to zero-discharge regulations. Development of all-electric is also important since subsea development is expected to be a part of the field development for 68 out of 88 discoveries on the Norwegian Continental Shelf (OG21, 2016).

Electricity for offshore structures is typically produced by gas turbines. The development of shore-based power in Norway fits well with all-electric subsea utilities. The recently developed oil giant Johan Sverdrup is powered by shore-based hydroelectricity, and the next step is set to include power transmission to other platforms located nearby, such as Edvard Grieg and Ivar Aasen (Equinor, 2020). Combining shore-based green power with all-electric subsea utilities will contribute to reduce the environmental footprint from field development and operation.

The OG21 strategy2 has identified development of all-electric subsea wells as a prioritized technology need, because it is seen as an enabler for new developments with longer tie-backs and locations in deeper waters.

2 OG21: Oil and gas for the 21^st century is a strategy project which has its mandate from the Norwegian Ministry of Petroleum and Energy. The OG21 strategy was last revised in 2016.

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1.2 Problem Formulation

The petroleum industry has acknowledged the benefits of electrification of the SPS both for technical, economical and for HSE. So it is no longer a question of “whether”, but rather “how

& when” (Abicht et al., 2017). Nonetheless, to prove that going all-electric is safe is the biggest obstacle for an all-electric subsea production system to be implemented in Norway. The explanation is that Norway has some of the strictest regulations of the petroleum industry worldwide. At the same time the Norwegian petroleum industry is innovative, so there is a continuous push & pull for better technology, such as all-electric.

Prior to implementing all-electric, the technology has to be qualified. Fundamental for the technology qualification process is the provision of evidence that the technology fulfills the requirements for the application area. The big challenge is therefore how to provide evidence of safety for an all-electric SPS when existing fail-safe requirements are prescriptive towards electro-hydraulic technology. This thesis aims to contribute to resolve this challenge by reviewing fail-safe principles, and how an all-electric subsea well can be isolated in the case of an emergency.

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1.3 Objectives

The objective of this master thesis project is to contribute to the characterization of the RAMS- aspects linked to going all-electric subsea, by making a comparison between two different valve actuation concepts, electro-hydraulic versus all-electric. With the following sub-objectives:

1. Briefly describe the challenges with current subsea technology and why the industry should go all-electric subsea. Give an introduction to the proposed architecture of an all-electric subsea field.

2. Present different concepts for electric valve actuators for use in gate valves (barrier valves), and review their fail-safe functionality. Compare these with the common hydraulic actuator.

Assess if the electric actuation concepts are compliant for use in the subsea Christmas tree.

3. Investigate the condition monitoring capabilities of an electric valve actuation system and the data available. Investigate the possibilities of partial stroke testing of an electrically actuated valve. Identify the effects of partial stroke testing on the system safety level, and investigate if partial stroke testing can be used to document diagnostic coverage (DC) of the valve actuation system.

4. Perform an individual FMECA on actuation control systems, one for the conventional electro-hydraulic system and one for the all-electric system. Use these individual FMECA’s for the comparison between the two systems, with focus on safety and reliability.

5. Identify the equipment needed for fulfilling the safety function of isolating an all-electric subsea well. Based on this information, propose an illustration of how to isolate the well.

Compare means of well isolation between the electro-hydraulic system and the all-electric system.

6. Investigate all-electric subsea wells’ position with regards to standards and guidelines. Are existing standards and guidelines compliant to qualify and certify all-electric subsea wells?

Review recommended practices for qualification of new technology. Finally, indicate what will be required in Norway for implementation of all-electric subsea wells.

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1.4 Approach

• The first three sub-objectives (1-3) are answered based on a literature review for which the basic foundation was established through my specialization project (J.Lindstad, 2019). Additional papers and book chapters have been reviewed throughout the master thesis work. The add-on contribution for this work and thesis has been increased insight.

• The fourth sub-objective is solved by two FMECAs. These two qualitative analyses are based on a thorough review of the sub-systems and equipment associated to both the electro-hydraulic and the all-electric system.

• The fifth sub-objective is answered based on a review of the 070 Norwegian Oil and Gas guideline – Appendix A.13 Isolation of one subsea well. Where the results from the literature review has been essential for the completion of this fifth sub-objective.

• The sixth sub-objective is answered based on a review of standards and guidelines related to subsea production systems, reliability and safety. This sub-objective is also approached by a review of recommended practices for technology qualification.

1.5 Contributions

• This thesis has contributed to the characterization of RAMS-aspects linked to going all- electric subsea by the performed analyses, and by a thorough review of research and technology development.

• The identification of the equipment involved in well isolation of an all-electric subsea well, combined with the system illustration, aims at contributing to an appendix for an all-electric subsea well in the 070 Norwegian Oil and Gas guideline. This can be seen as a contribution towards the process of implementing all-electric subsea wells in Norway.

• The thesis has shed light on fail-safe principles for valve actuators and challenges related to technology qualification of subsea systems.

1.6 Limitations

The FMECAs performed on the electro-hydraulic system and the all-electric system focus on the main systems and equipment involved. This approach ensures a fair comparison of safety and reliability for both systems. The boundaries for the analyses has been set to focus on the systems and equipment located subsea, topside located equipment is accordingly out of the scope. Finally, the source of the electrical power supply is out of the scope for this thesis work.

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1.7 Outline

This master thesis report, contains eight main chapters:

• Chapter 1. Introduction: introduces the background, problem formulation, objectives and what the thesis contains.

• Chapter 2. Subsea Production: gives an introduction to the fundamentals of subsea production systems, subsea Christmas trees and gate valves. In addition, the chapter reviews the current electro-hydraulic control system, an all-electric subsea system, related subsea standards, use of subsea production systems, subsea history and development drivers.

• Chapter 3. Theoretical Background: contains an introduction to relevant reliability theory, and a review of the associated standards and guidelines.

• Chapter 4. Valve Actuators, Data Available and Partial Stroke Testing: reviews different valve actuators for use in subsea Christmas trees. The chapter also reviews the data available from an electric valve actuation system, and partial stroke testing of valves.

• Chapter 5. Reliability Study: describes the analyses conducted and how well isolation of an-electric subsea well may be performed.

• Chapter 6. Results: presents the main results from the performed analyses, and compares means of well isolation between the electro-hydraulic system and the all- electric system.

• Chapter 7. Discussion and Analysis: discusses and analyzes the findings regarding the thesis’ sub-objectives. The chapter is finalized by an assessment of the accomplishments.

• Chapter 8. Conclusion and Recommendations for Further Work: presents these and ideas for continuance of this master thesis work.

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8 The purpose of this chapter is to give an introduction to subsea production and to summarize the literature review. It contains eight sub-chapters.

2.1 Introduction to Subsea Production Systems (SPS)

Subsea production is equipment installed on the seabed to produce hydrocarbons from subsea wells. Going subsea facilitates production from oil & gas fields located at deeper waters, further offshore and at more remote locations. Subsea production also gives extended horizontal reach from a platform facility, to enable tie-in and production from reservoirs located further away from the host facility. Subsea production makes the development of smaller petroleum reservoirs more economically profitable. The subsea production system consists of:

• Subsea well: equivalent to a surface- or platform-based well, with the exception that wellhead is located on the seabed.

• Subsea wellhead: a pressure containing profile to place the subsea Christmas tree onto.

• Subsea Christmas tree (XT): provides access to and control of the subsea well. Subsea XTs are also called “wet trees” since they are submerged in water.

• Manifolds: structures that commingles and distributes the production from the wells.

• Flowlines and risers: are pipelines which distributes the production from subsea to the topside facility. Flowlines are subsea pipelines placed on the seabed, while risers are flowlines which lay in the water column connecting the subsea equipment to the topside facility.

Subsea production can be from a single well using a pipeline end manifold (PLEM-manifold), or from multiple wells using a template or cluster-based manifold. The integrated template structure (ITS) is a manifold type which is commonly used in Norway. The ITS provides protection from fish trawling nets. The SPS equipment is installed to remain on the seabed throughout the fields lifetime, and is categorized as “long stay” equipment with a specified lifetime of 20-30 years. It is fundamental that this equipment shall only require retrieval for repair or reconfiguration (Moe et al., 2018). This is due to costs associated with accessing the installations, but also due to access-related challenges. Access to many subsea production systems on the Norwegian continental shelf are restricted periodically throughout the year due to severe sea states, which commonly occurs during the autumn and winter season.

2 Subsea Production

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2.2 Subsea Christmas tree (XT)

A Subsea Christmas tree (XT) is a steel block that contains bores and valves. The Christmas tree is placed on top of top the subsea wellhead, and can be either vertically or horizontally configured, of which vertical XTs are most common. The main difference between the two is the location of the valves and tubing hanger. The subsea Christmas trees are controlled from a master control station located at the topside facility. The functions of a Christmas tree is (070 NOG, 2018; NORSOK D-010, 2013; Bai and Bai, 2012):

• Regulate the hydrocarbon flow conduit from the XT to further distribution to flowlines and manifolds, by controlling valves and chokes,

• Ability to safely shut down production by closing the choke valve and/or the master valves,

• To safely isolate the reservoir from the environment by closing the master valves,

• Allow for chemical injections in the well,

• Monitor and control the pressure in the well annulus,

• Allow for well interventions by the use of vertical tooling.

As a result of these requirements, almost all the valves in a subsea Christmas tree are required to have fail-safe-close functionality, enabling them to close in the case of a power or communication failure (070 NOG, 2018; NORSOK-D010, 2013; Bai and Bai, 2012).

The master valves on the Christmas tree, in addition to the downhole safety valve are the reservoir barrier. Since the subsea production system needs to close the master valves in situations even when hydraulic supply or electrical power signal is lost, the energy for the fail- safe-close functionality needs to be stored subsea (Torbergsen et al., 2012). State of the art is to store this energy in a compressed metal spring.

Figure 1 shows a simplified illustration of a conventional dual bore vertical Christmas tree in accordance with ISO 13628-4 (2010). All the valves displayed with a rectangular are remotely operated with a fail-safe-close functionality according to 070 NOG (2018).

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10 Figure 1 Dual bore vertical XT

The bore on the right in Figure 1 is the production bore, i.e. the main bore, as displayed by a thicker line. It has three barrier valves in series configuration in the flow path: First, the downhole safety valve (DHSV); Second, the production master valve (PMV); Third, the production wing valve (PWV). These three valves are open during normal production. The DHSV3 is the primary barrier, while the PMV and the PWV represents the secondary barriers, which constitute redundancy in the flow path. Moreover, the production choke valve (PCV) is used to regulate the hydrocarbon flow with a fail-as-is/ fail-in-position functionality. The left bore is the annulus bore, and its purpose is to provide access for well interventions. The annulus

3 The DHSV is also named: surface controlled sub-surface safety valve (SCSSV).

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11 valves are closed during normal production. The cross-over valve (XOV) provides communication between the normally isolated annulus- and production-bore. The XOV can be used to shut down the well by providing fluid passage for “well kill” operations, and to overcome blockage or hindrance due to hydrate formation. The swab valves in the bores, the annulus swab valve and the production swab valve are closed during normal production and are only open to provide access for well intervention when the production is shut down. (Bai and Bai, 2012; Berge Gjersvik, 2019a; Torbergsen et al., 2012)

2.3 Gate Valves

The master valves in the Christmas tree and the downhole safety valve are gate barrier valves with an on-off flow regulating function, i.e. they are either fully open or fully closed. Gate valves have a barrier safety functionality, which means that they are able to shut off flow in the case of emergency situations or shutdowns. In the fully open position the gate valve provides full flow with a very small pressure drop (Sutton, 2017). There are two design configurations available for subsea gate valves (Berge Gjersvik, 2019a):

• Balanced gate valve: the valve stem is subject to the full hydrostatic pressure at both ends of the valve stem. Balanced designs are applied at water depths exceeding 1500m.

• Unbalanced gate valve: the valve stem is subject to the hydrostatic pressure only at the

“upper end” of the valve stem. Unbalanced design is applied at water depths less than 1500m.

Figure 2 shows the main components of a unbalanced gate valve operated by a hydraulic actuator. The valve is in the open position, and when it is closing the gate and piston moves rightwards. The valve opens and closes by sliding a rectangular gate with a bore equal to the production well bore. A hydraulic piston connected to the stem moves the valve gate. The valve actuator is fail-safe-close configured by a metal spring, and the valve is normally closed. To open the valve, hydraulic control pressure on the piston compresses the spring.

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12 Figure 2 Unbalanced valve with spring and hydraulic actuator (valve is open)

- Courtesy FMC Technologies (Tor Berge Gjersvik, 2019)

When the valve is in the open position, the spring is fully compressed. The spring is then energized, and it will continue to exert a force on the piston. This ensures that the valve will close and remain closed in case of an emergency shutdown. The valve will remain open as long as there is sufficient hydraulic pressure on the actuator. The valve is connected to an emergency shutdown (ESD) system. In case of electrical power cut, or if hydraulic pressure bleeds off, the valve will close. When the valve is in the closed position the hydraulic control fluid is vented out of the actuator, either to be returned to topside in the case of a closed-loop arrangement, or vented to the sea in an open-loop arrangement.

A typical size and pressure rating of a Fail-Safe-Close PMV and PWV is 5 1/8-inch (130 mm) and 10 000psi (690bar)4 (Berge Gjersvik, 2019a; Torbergsen et al., 2012). The selection of the pressure rating is determined by the water depth and the well pressure (WP).

4 Note that 1.01325 bar is equivalent to standard atmospheric pressure (1 atm). These units belong to the International System of Units (SI). Psi (pounds per square inch) is a pressure unit belonging to the Imperial system of units, which are units commonly used for specifications in petroleum engineering.

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2.4 Electro-Hydraulic Control System

The multiplexed electro-hydraulic control system is the common system for subsea control. In this system, control of subsea utilities is exercised based on a hydraulic power unit (HPU) and an electrical power unit (EPU), both located topside. The subsea production system is controlled by the means of an umbilical. The umbilical is a hose-like structure that transmits hydraulic- and electrical-power from a topside facility and down to equipment on the seabed. In addition, the umbilical also contains lines for transmission of chemicals for injection subsea, as well as communication lines.

The hydraulic system consists of two different supply circuits (Bai and Bai, 2012), one is a low pressure (LP) circuit, while the other is a high pressure (HP) circuit. The LP circuit is for control of XT valves and manifold valves, and typically has a differential pressure around 210 bar. The HP circuit is purely for the down hole safety valve (DHSV), and typically has a differential pressure between 345 to 690 bar. The required pressure for LP and HP depends on the water depth at the field location, amongst other factors. The umbilical contains an individual line for each of the hydraulic circuits, and each of the hydraulic circuits commonly contain spare (redundant) hydraulic lines (Elgsaas et al., 2018). Including spare lines are cheaper than replacing the whole umbilical in case of a failed line.

Most hydraulic-control systems are “open-loop” systems, which means that hydraulic fluid, is vented to sea during valve closure. The hydraulic control fluid is commonly a water based fluid, and it is classified as a “green” chemical. The amount of control fluid vented from closing a master valve is only a few liters (Berge Gjersvik, 2019b). The vented volumes do not accumulate to a big volume as valve operations are not frequently performed. There exists

“closed-loop” systems, but they are rare. The Kirinskoye field located in the Sea of Okhotsk in Russia is an example of a closed-loop system (Smedsrud, 2011). The motivation for installing a “closed-loop” system is environmental restrictions by regulatory authorities at the given location, e.g. zero-discharge. These “closed-loop” systems give increased complexity, as return lines are required within the umbilical, and hence increases the umbilical cost.

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14 Figure 3 shows the main components and sub-systems in the multiplexed electro-hydraulic control system based on Bai and Bai (2010). A simplified cross-section of the control umbilical5

is shown at the top right side of the figure.

Figure 3 Electro-hydraulic control system

5 Note that spare hydraulic lines are not shown in the simplified cross-section of the umbilical.

The dimension range of the outer diameter (OD) of the umbilical is based on the world’s largest umbilical diameter: 325mm (as of 2014). This umbilical was also the heaviest umbilical installed at the time, weighing 200kg/m. This umbilical was installed at the field hosted by the Skarv FPSO in Norway.

The Skarv FPSO is shown in Figure 8. (OFFSHORE ENERGY, 2014; TechnipFMC, 2020).

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15

2.5 All-Electric Subsea

This sub-chapter presents the background for the transition towards all-electric subsea fields.

2.5.1 Transition towards All-Electric Subsea Fields

In my recent specialization project (J.Lindstad, 2019), I reviewed the transition towards all- electric subsea fields and found the following:

“All-electric control would be favourable to use when developing marginal fields at great distances from a processing facility”(Jernström et al., 1993). This argument coincides with the current arguments of the oil & gas industry, and it is based on analyses predicting reduced costs for the all-electric subsea system.

Elgsaas et al., (2018) links the arrival of subsea electrification to drivers such as reduced costs of electric actuators and electric systems proven reliable. “The general industry trend is very visible today, exemplified by electrically powered cars and ferries, and by electric control ranging from airplanes to process plants” (Moe et al., 2018).

The oil & gas industry has acknowledged the benefits of electrification, and the application of electric technology in subsea solutions have been increasing throughout the past years. This is exemplified by the move from the first direct hydraulic control system to the multiplexed electro-hydraulic (EH-MUX) system in use today.

Elgsaas et al. (2018) connects the increased interest in electric technology with subsea electric valve actuation gaining a track record of more than 15 years with good operation, and this history is confirmed by (Abicht et al., 2017; Moe et al., 2018).

Moe et al. (2018) anticipates that electric solutions will become even more important in future subsea fields, due to their location and zero discharge policies at these locations. Activities like gas compression and oil boosting is now being done subsea. An example of an all-electric control system is Equinor’s Aasgard subsea gas compressor which is controlled by 78 electric actuators (Time and Torpe, 2016; Moe et al., 2018).

All-electric systems lend itself easier to monitor versus hydraulic equipment. For example, the electrical power needed to execute a given command could be used as an indicator for the

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16 condition of the associated equipment. If the power consumption exceeds the mean power consumption for the given command, such as opening or closing a gate valve, this could indicate degradation. A worn and degraded valve is likely to experience increased friction during opening or closing, and this is expected to increase the power demand required for those commands.

All-electric systems aids intelligence by inherently producing high quality data. These data are continuously produced from “motor controllers, control boards and batteries” (Elgsaas et al., 2018). The continuous data logging facilitates accurate condition monitoring, which can be used to indicate the current state of the system’s condition. This implies that degradation and potentially degradation modes could be identified through monitoring, and that prediction models could be built based on history data, e.g. by applying machine learning algorithms, and this could enable predictive maintenance subsea. (Elgsaas et al., 2018)

2.5.2 Categorical Drivers for All-Electric Subsea

As introduced in the thesis introduction there are three technology drivers for transitioning to an all-electric subsea production system, i.e. technical, economical and HSE as shown in Table 1.

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17 Table 1 Drivers for all-electric

Technical Economical HSE

Simplified umbilical (reduction of cross-sectional area) eases fabrication, transportation and installation.

Simplified umbilical directly reduces the umbilical cost, plus installation cost (CAPEX).

Removal of personnel exposure to hydraulic fluids and highly pressurized equipment (during testing, transportation, offshore operation and maintenance).

Standardization and

simplification will allow for scalable modules and reduce the time required for EPC.

(Current electro-hydraulic systems are often tailor made)

Standardization gives scalable modules which reduces EPC costs, as the configuration time is reduced. (CAPEX)

Standardization may reduce the risk of human failures related to either installation or operation.

Reduced topside weight and space required by removal of the hydraulic power unit (HPU) system.

Reduced topside cost by removal of the HPU system (CAPEX and OPEX).

Less personnel required offshore due to the removal of the hydraulic systems. This indirectly improves HSE.

Potential enabler for unmanned platforms.

Reduced weights (manifolds, XTs and other subsea modules) due to removal of the hydraulic system.

Lighter subsea modules reduce the cost of hardware and installation (CAPEX).

Reduced carbon footprint as the weight of the modules are reduced. This will enable the use of smaller installation vessels.

Simplified testing:

Significantly reduced duration of various tests as the control systems are simplified.

Reduced complexity of commissioning due to removal of the hydraulic system.

Start-up times under

commissioning and following an ESD will be significantly reduced.

Reduced test duration reduces the costs (OPEX).

Significantly reduced start up times following an ESD reduces the production interruption losses.

Quicker production start-up from the field is positive for the revenues (NPV).

Offshore personnel are no longer exposed to the hydraulic systems during various tests and commissioning.

Increased production uptime by removal of all hydraulics related failures.

Increased uptime (availability) gives increased production, which is positive for the revenues (NPV).

Less maintenance and interventions.

(Abicht et al., 2017; Berge Gjersvik, 2019c; Elgsaas et al., 2018; Johansen et al., 2017; Kalia, 2019;

Melbø, 2019; Moe et al., 2018)

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18 Expenditures Savings

The CAPEX savings for a control umbilical can typically be 1 million NOK6 per km (100 000 US dollars per km), by removing the LP and HP hydraulic supply lines within the umbilical (Moe et al., 2018). The total CAPEX savings for the subsea production system is expected to be between 7-14% (Abicht et al., 2017). Removal of the hydraulic systems will also reduce OPEX associated with the hydraulic system, due to removal of associated costs such as:

hydraulic fluid consumption, testing and flushing. In addition, removal of the HPU at the topside facility will give overall expenditure savings. Nonetheless, the most significant economic impact will be increased profits due to increased production availability (uptime).

2.5.3 Current use of Electric Actuators Subsea

Electric actuation of choke- and manifold-valves have been used for more than 15 years, and proven to be successful. The current applications of electric actuators have been in valves with a “fail-as is” or “in position” functionality requirement (Abicht et al., 2017; Moe et al., 2018).

The applications have not been in safety critical valves. Two “fail-safe-close” valve actuators were installed as a pilot system in field in 2005, where Equinor is the operator (Moe et al., 2018;

Offshore Magazine, 2006). These actuators had an integrated battery dedicated to power valve closure, in case of a power supply- or communication- loss.

Technological development is a step-wise approach, and implementation of new equipment and technology happens in stages. New technology is accordingly often tested in non-safety critical applications. Figure 4 shows the step-wise approach of SPS electrification.

6 Based on a currency exchange price: 9.96 NOK per 1 USD as of 19.05.20 (dd.mm.yy).

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19 Figure 4 Step-wise approach of SPS electrification – Based on Melbø (2019)

An application example of the first step (1) shown in the figure is battery-based actuators that were retrofitted on manually operated choke valves on the Statfjord satellite subsea wells in the early 2000s (Moe et al., 2018). The application in choke valves has the fail-as-is/ fail-in-position requirement. The field is operated by Equinor and is still producing. The need for deploying battery-based electrical actuator arose from a weak power infrastructure. The second step (2) has partly been realized as electric actuators have been used in manifold valves for many years.

The third step (3) for the industry is to use electrical actuators in safety critical applications with fail-safe-close requirements. This involves application in the subsea Christmas tree and the downhole safety valve (DHSV). Application of technology in XT valves and DHSV are subject to fulfill strict safety ratings due to their barrier functionality.

Current use of Electric Christmas Trees

Currently there are three electrical Christmas trees in production in the Dutch sector of the North Sea. They are employed at the K5F field which is operated by Total. Total features all- electric technology as one of the main technologies enabling cost reduction for offshore developments. The three XTs are designed for gas production and controlled by a dedicated electric control system which is described by Schwerdtfeger et al. (2017). The XTs are powered and controlled from a platform facility through an 18km long umbilical. All three XTs are powered by electric cables (direct current), and the system does not utilize subsea batteries.

The electric Christmas Tree is in principle equal to a Christmas Tree operated by the electro- hydraulic system, it just has more electric components and connectors. All the valves with

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20 barrier functionality installed at the all-electric subsea well K5F3 are equipped with electric spring-based actuators, even the down hole safety valve. This well is a pilot-project, so in order to gain project acceptance, the well has a conventional hydraulic DHSV in backup.

(Offshore Technology, n.d.; Pimentel et al., 2016; Schwerdtfeger et al., 2017; Total, 2016a, 2016b)

2.5.4 All-Electric Subsea Field Architecture

J.Lindstad (2019) identified equipment and systems that are affected by a transition to all- electric solutions. The subsea control system (SCS) is governing the change as equipment and systems needs to be designed for electrical power as the power supply. Going all-electric subsea will remove the hydraulic systems. This will simplify the umbilical, save space on the topside facility and it will result in zero-discharge of control fluid to the sea. Electric valve actuation will have a very short response time, and the number of valve commands will not be limited as for the electro-hydraulic control system. This will enable new operation modes of the SPS.

More frequent operation of valves and regulation of valve positions have been predicted to characterize these new operation modes.

Figure 5 shows a simplified layout of an all-electric subsea control system. The layout is constructed based on Bai and Bai (2012); Mahler et al. (2019); Schwerdtfeger et al. (2017).

Fundamental for this control system is the conversion of high voltage electrical power into low voltage power in the power regulation module subsea, as well as the use of subsea batteries for local energy storage. The switch module is another characterizing component in this system architecture.

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21 Figure 5 All-electric control system

Moe et al. (2018) shows that an all-electric control umbilical* can have a 30% reduction of the cross-sectional area compared to a conventional electro-hydraulic control umbilical.

Subsea Batteries

J.Lindstad (2019) found that an all-electric subsea field would have a strong dependency on batteries, and the following is based on previously conducted work, with a few key supplementations. Subsea batteries are required when the electrical power supply from the topside facility is not sufficient to power the valve actuators. The batteries may be stored in dedicated modules, within valve actuators, or in canisters at the various subsea equipment.

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22 Subsea batteries are “trickle-charged” which means that they are charged at their discharge rate when fully charged. This results in fully charged batteries at all times when unloaded.

Depending on the chosen gate valve actuation concept, the batteries may also be required to provide power for valve closure, substituing the common fail-safe spring.

Li-Ion batteries are the best fit, i.e. compared to other battery types, for subsea application due to power, size and weight (Johansen et al., 2017). This battery type benefit from the low ambient seawater temperatures that characterize most subsea fields. Reliability analysis performed on batteries for subsea application has shown that redundancy should be implemented on the battery system level, and not on the battery cell level (Winter et al., 2019). This implies that redundant configuration of batteries will be required. The battery system architecture for a subsea Christmas tree needs to consist of several independent battery channels. Each battery contains multiple battery cells in a series configuration. This cell configuration provides a high voltage and reduces the current of the battery (Winter et al., 2019). Figure 6 shows the principal idea behind the battery channels.

Figure 6 Redundant battery channels (centrally located)

Analysis has shown that centrally located batteries (e.g. within the SCM) give better availability and reduced costs, compared to integrating the batteries within each electric actuator (Mahler and Glaser, 2018). Batteries have proven to be reliable subsea, but most applications have been without formal safety certified functionality (Moe et al., 2018). This implies that the applications have not been for valves with barrier functionality. In the future all-electric subsea field, batteries will be required to compensate for the lack of a mechanical fail-safe mechanism currently required in XT master valves and the down hole safety valve. (Moe et al., 2018)

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23 2.5.5 Implementation of All-Electric Subsea Wells

All-electric systems represent a fundamental technology change for the subsea production system. Moe et al. (2018) suggests a risk mitigated implementation of all-electric technology, and highlights infill wells as ideal candidates. This application reduces the risk associated with implementing new technology and also the associated costs. From a risk management perspective infill wells (is a well installed amongst currently producing or developed wells) appears to be the best application area for deployment of all-electric technology. Fields where the hydraulic system capacity is already fully utilized (“used up”) are therefore good candidates for implementing electric actuators. The electric system is expected to give increased flexibility in field developments as electric actuators can be retrofitted, utilizing reserve capacity in powerlines in existing umbilicals. For a full all-electric field development, the best business case is long distance gas fields due to the long control umbilical. For such cases the CAPEX savings will be large, especially with regards to the umbilical. (Moe et al., 2018).

2.6 All-Electric versus Standards for Subsea Production Systems

Current standards and guidelines give directions based on an electro-hydraulic system, i.e. there is no all-electric standard available. All-electric subsea wells therefore require update of standards and guidelines in order for qualification and verification. The Norwegian petroleum industry are subject to some of the strictest regulations and requirements worldwide.

Qualification of all-electric subsea wells in Norway is accordingly assumed to imply qualification for most countries with petroleum resources. Table 2 shows relevant standards for design and operation of subsea production systems.

Table 2 Relevant standards and guidelines for subsea production systems Standards and guidelines Title

International Organization for Standardization

ISO 13628-4 (2010)

Petroleum and natural gas industries — Design and operation of subsea production systems — Part 4: Subsea wellhead and tree equipment

ISO 13628-6 (2006) Petroleum and natural gas industries — Design and operation of subsea production systems — Part 6: Subsea production control systems

American Petroleum Institute API 17D (2011)

Design and Operation of Subsea Production Systems - Subsea Wellhead and Tree Equipment, Second Edition

(Is an identical national adoption of ISO 13628-4)

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24 The ISO 13628-4 (2010) standard for subsea Christmas trees does not specify the means of actuation of the tree valves (section 6.2 Tree valving). Nonetheless, the standard only provides requirements for hydraulic actuators, for which it specifies the following requirements (section 7.10.2.2.4):

• Manual overrides for fail-closed valve shall open the valve with a push on the override (push-pull type override).

• The fail-safe mechanism in the actuator shall be designed and verified to provide a minimum spring life of 5000 cycles.

The first requirement is defined for a rising stem gate valve, while the second requirement is directly defined for a fail-safe close mechanism provided by the mechanical spring module.

The second requirement is prescriptive with regards to a spring-based actuator.

These findings are supported by similar findings made by Johansen et al. (2017) in the American adoption (API 17D) of the ISO standard.

The ISO 13628-6 (2006) standard gives the main requirements for subsea production control systems. The main part of the standard gives requirements and directions based on a hydraulic control system, either direct hydraulic or electro-hydraulic. Nonetheless, the standard does include an appendix (annex) for electric control systems. The standard was last reviewed and confirmed in 2015, and gives requirements for qualification testing of equipment, but gives no specifications regarding new technology. Johansen et al. (2017) states that the requirements in the ISO 13628-6 standard has been used to provide guidance for compliance, due to the absence of standards related to new technology. The result of this may be that qualification of technology is done according to test requirements which are irrelevant, or that differs from the operational characteristics of the technology to be qualified (Johansen et al., 2017). For safety critical subsea systems like Christmas trees, this approach is intolerable.

2.7 Use of Subsea Production Systems

Subsea production systems (SPS) are utilized in three field concepts:

• Tie-in of subsea wells to a fixed platform structure (which has platform-based wells),

• Floating offshore structure connected to subsea wells,

• “Subsea-to-shore”, which is a concept without an offshore structure.

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25 The first SPS concept is used in addition to platform-based wells located on a fixed offshore structure. The term “fixed” means that the offshore structure is built on legs anchored directly to the seabed. These platforms typically host production facilities, drilling facilities and living quarters for offshore personnel. In addition, the main field developments usually host hydrocarbon processing facilities. These structures have a limited number of well slots available on the platform facility. The horizontal reach from the platform’s drilling system is limited.

Development and tie-in of subsea wells gives extended horizontal reach from the platform, and allows for access to a greater area of the reservoir. The recent oil giant Johan Sverdrup is located at shallow water (110-120m), and thus employs a fixed platform facility hosting platform-based wells. Johan Sverdrup will in the near future employ the first SPS concept, and this represents phase II of the development. Figure 7 shows the platforms at the Johan Sverdrup field, which is located west of Stavanger, Norway. (Equinor, 2020; Norwegian petroleum, 2020)

Figure 7 Johan Sverdrup platforms - Courtesy Equinor ASA

The second SPS concept is used when the water depth exceeds a certain water depth, roughly 300-400m. In this water depth fixed platforms are not a feasible solution with regards to economy and engineering. Instead, floating offshore structures are used, e.g. an FPSO or a semi- submersible platform. Floating offshore structures are connected to subsea by flexible risers, and they are moored to the seabed. Figure 8 illustrates the Skarv FPSO which is producing from the Ærfugl subsea field outside Sandnessjøen, Norway. As shown in the illustration, multiple wells access the reservoir. The composition of the reservoir is illustrated by color highlighting, where the blue color represents the water, green the oil and red the gas.

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26 Figure 8 Subsea production by FPSO – Courtesy Aker BP

The third concept is independent of an offshore structure, where the produced hydrocarbon stream is transported directly by pipeline to a shore-based facility for processing. This concept is used at the Ormen Lange gas field outside Molde, Norway. The wellstreams from Ormen Lange is distributed by two subsea pipelines to the shore-based facility Nyhamna in Aukra, Norway for processing. Figure 9 illustrates the Ormen Lange field, which is a gas and condensate field. The red color highlighting shows that this is a gas field. The “subsea-to- shore” concept is best suited for gas fields due to the fluid phase composition.

Figure 9 Ormen Lange - Courtesy A/S Norske Shell

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27

2.8 Subsea History and Development Drivers in Norway

The discovery of the giant Ekofisk field in the fall of 1969 represents the beginning of the Norwegian petroleum era. The production started in July 1971 from Norway’s first subsea well, and by February 1972 a total of four subsea wells were in production. All of the four corresponding XT’s were made in the USA, and these were originally “dry trees”, which means that they were built for platform-based wells. However, the XT’s had been modified to cope with the seawater environment; ambient pressure and the corrosive environment. The XT’s were hydraulically operated and had a lower master valve with a manual operated wheel for diver operation. The emerging subsea sector depended on diver assistance for installation and modifications. Figure 10 shows one of the four XTs from Ekofisk.

The installation of the XT’s at Ekofisk represented a technical milestone, as subsea trees had not been installed in such weather exposed locations and at such depths before (ca. 70m). The further development of discoveries such as Frigg and Statfjord in 100 and 150-meter water depths resulted in financial optimism among the oil companies.

However, the challenge was that two-thirds of the Norwegian continental shelf is located at depths greater than 200 meters. At the time, oil & gas fields had yet to be developed at such depths.

In the beginning the Norwegian oil industry relied upon imported technology. By the end of 1972, there were three Norwegian petroleum companies, Norsk Hydro, Saga Petroleum and Statoil. A few years after Ekofisk started

producing, Norwegian companies started developing subsea technology as a new business area.

The development of remotely operated vehicles (ROVs) and remotely operated tools (ROTs) were key to make subsea systems diverless. The Gullfaks A satellite wells represents the first Norwegian subsea development without diver assistance. The wells were developed by the Norwegian arms manufacturer “Kongsberg våpenfabrikk” and Statoil, and the initial well began producing in December 1986. The development was a pioneering achievement at the time. The

Figure 10 XT which produced at Ekofisk - Courtesy Jan A

Tjemsland

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28 discovery of the Troll field in 1979 lead to an increasing interest in diverless solutions. The Troll field is located at 300-350m water depth which exceeds the reach of routine diving.

By the 1990s, subsea solutions were cost-effective compared to platform solutions.

Maintenance became easier in deep waters due to the modular approach of the subsea solutions, and standardization in subsea solutions led to quicker deliveries and reduced costs of engineering. The Norwegian subsea history has shown that it is important to develop new technologies, and overall risk aversion has never characterized the Norwegian oil & gas development.

Unlike in many other countries, a solid regulatory regime for the petroleum industry have been developed by the Parliament (Stortinget), Norwegian Petroleum Directorate (NPD) and Petroleum Safety Authority (PSA). Typical requirements to comply to include responsible resource management, achieving the highest possible recovery factor from the reservoir and reducing pollution to a minimum. The government has also been a driver and facilitator for Norwegian companies to develop and select subsea technology at the earliest possible phase in field developments. (Gjerde and Nergaard, 2019)

Safety and Reliability Assessment of All-Electric Subsea

Master ’s thesis

Jon Anders Søberg Lindstad

Safety and Reliability Assessment of All-Electric Subsea

Jon Anders Søberg Lindstad

Safety and Reliability Assessment of All-Electric Subsea

Preface

Acknowledgement

Executive Summary

Sammendrag

Table of Contents

List of Figures

List of Tables

Abbreviations

1.1 Background

1 Introduction

1.2 Problem Formulation

1.3 Objectives

1.4 Approach

1.5 Contributions

1.6 Limitations

1.7 Outline

2.1 Introduction to Subsea Production Systems (SPS)

2 Subsea Production

2.2 Subsea Christmas tree (XT)

2.3 Gate Valves

2.4 Electro-Hydraulic Control System

2.5 All-Electric Subsea

2.6 All-Electric versus Standards for Subsea Production Systems

2.7 Use of Subsea Production Systems

2.8 Subsea History and Development Drivers in Norway