subsea hvdc connectors technical gaps analysis final report · for dry-mate (dm) connectors....

Subsea HVDC Connectors Technical Gaps Analysis Report, Project 12121-6302-01, GE Global Research

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RPSEA

Subsea HVDC Connectors Technical

Gaps Analysis Final Report

12121.6302.01.02

Qin Chen (GE Global Research)

Subsea High Voltage Direct Current Connectors

for Environmentally Safe and Reliable Powering

of UDW Subsea Processing

12121-6302-01

April 21, 2015

Qin Chen (Principal Investigator)

Electrical Engineer

GE Global Research

1 Research Circle, Niskayuna, NY 12309


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LEGAL NOTICE

This report was prepared by GE Global Research as an account of work sponsored by the Research

Partnership to Secure Energy for America, RPSEA. Neither RPSEA, members of RPSEA, the National

Energy Technology Laboratory, the U.S. Department of Energy, nor any person acting on behalf of any

of the entities:

a. MAKES ANY WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED WITH RESPECT TO

ACCURACY, COMPLETENESS, OR USEFULNESS OF THE INFORMATION CONTAINED IN THIS

DOCUMENT, OR THAT THE USE OF ANY INFORMATION, APPARATUS, METHOD, OR PROCESS

DISCLOSED IN THIS DOCUMENT MAY NOT INFRINGE PRIVATELY OWNED RIGHTS, OR

b. ASSUMES ANY LIABILITY WITH RESPECT TO THE USE OF, OR FOR ANY AND ALL DAMAGES

RESULTING FROM THE USE OF, ANY INFORMATION, APPARATUS, METHOD, OR PROCESS

DISCLOSED IN THIS DOCUMENT.

THIS IS AN INTERIM REPORT. THEREFORE, ANY DATA, CALCULATIONS, OR CONCLUSIONS REPORTED

HEREIN SHOULD BE TREATED AS PRELIMINARY.

REFERENCE TO TRADE NAMES OR SPECIFIC COMMERCIAL PRODUCTS, COMMODITIES, OR SERVICES IN

THIS REPORT DOES NOT REPRESENT OR CONSTITUTE AND ENDORSEMENT, RECOMMENDATION, OR

FAVORING BY RPSEA OR ITS CONTRACTORS OF THE SPECIFIC COMMERCIAL PRODUCT, COMMODITY,

OR SERVICE.


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ABSTRACT

This document presents the results of the Technical Gap Analysis for subsea DC cable connectors

performed in RPSEA project 12121-6302-01. DC connectors are critical components in subsea DC

electrical transmission and distribution systems, which are used for powering subsea oil and gas fields

with high power, long step-out distance, and deep water depth. Currently there are no DC connectors

commercially available satisfying the need for future subsea DC systems. On the other hand, there are

existing technologies that are related to subsea DC connectors, such as subsea AC connectors and land-

based high voltage DC systems. The technical gap for the subsea DC connectors is analyzed by

comparing the technical requirements for these connectors (obtained from earlier study in the same

project) and the state-of-the-art of the relevant existing technologies. The risks and uncertainties that

cannot be addressed using existing technologies will be identified as development needs. A technical

gap closing strategy for the current RPSEA project is proposed based on classification and prioritization

of technical risks and uncertainties.


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Technical Gap Analysis Report

GE Global Research – Project Number 12121-6302-01

Table of Contents 1. Introduction .......................................................................................................................................... 5

List of Abbreviations ..................................................................................................................................... 7

Definitions ..................................................................................................................................................... 8

2. Technical Gap for Subsea DC Connectors ........................................................................................... 10

2.1. Review of technical requirements .............................................................................................. 10

2.2. Technical risks and uncertainties for subsea DC connectors ...................................................... 11

Challenges associated with DC electrical operation ........................................................................... 11

Challenges associated with subsea installation and operation .......................................................... 17

Challenges associated with DC + subsea combination ....................................................................... 18

2.3. Review of relevant technologies ................................................................................................. 28

2.4. Summary of technical gaps ......................................................................................................... 36

3. Gap-Closing Strategy in the RPSEA Project ......................................................................................... 37

3.1. Preliminary engineering design ...................................................................................................... 38

3.2. Gap-closing strategy for RPSEA project .......................................................................................... 43

4. Summary ............................................................................................................................................. 49

References .................................................................................................................................................. 50

Appendix: Minutes of Meeting, Second Open Industrial Workshop .......................................................... 53

1. Introduction

Subsea DC transmission and distribution (T&D) is a promising technology to provide a reliable,

environmentally friendly, and economic solution for powering ultra-deepwater (UDW) subsea

processing plants with long step-out distance and high power. A subsea DC system consists of high

voltage DC transmission cables, electric power components (e.g., power electronics modules for DC-DC

or DC-AC power conversion), distribution cables (DC and AC), and loads (e.g., AC motors) (Figure 1). As

the interfaces between cables and electrical power components and loads, the cable connectors are

critical components in such a system.


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At the beginning of the current RPSEA project a Technical Requirements Analysis was performed. The

study included an analysis on the electrical responses of a general subsea DC electrical system. As part

of the study an open industrial workshop was organized to gather input from industrial subject matter

experts regarding the needs for subsea DC connectors in offshore oil and gas applications. The results of

this study have been described in the Subsea HVDC Connectors Technical Requirements Report [1].

Currently there are no subsea DC connectors available at >10kV voltage rating, whereas the need for

voltage ratings of up to 150 kV DC is indicated by the technical requirement analysis. On the other hand

certain existing technologies are related to subsea DC connectors. For instance, subsea AC connectors

are commercially available with voltage ratings up to 36kV for wet-mate (WM) connectors and 145kV

for dry-mate (DM) connectors. Moreover, high voltage DC transmission systems between land-based

terminals are available for up to 800 kV DC (overhead line based systems) and 500 kV DC (systems with

underground or submarine cable links). With regards to the development of subsea DC connectors, the

question is what can be leveraged from the existing technologies and what is missing from these

technologies and requires new development. Moreover, the identified technical challenges for the

subsea DC connectors should be classified based on their nature, and within the RPSEA project priority

should be given to addressing the fundamental development needs rather than engineering challenges.

These issues are to be analyzed in the present document.

This report consists of two major parts. In the first part the technical gap for subsea DC connectors is

analyzed. The technical requirements for these connectors are first reviewed, and the major challenges

associated with these requirements are discussed. Then, by comparing to the various existing

technologies, the technical challenges for the subsea DC connectors are identified. The second part of

this report focuses on the gap-closing strategy in the current RPSEA project. The technical challenges for

the subsea DC connectors are classified into fundamental development needs and engineering

challenges. A preliminary engineering design is presented, which provides a guideline to estimate the

engineering complexity of developing subsea DC connector prototypes with different ratings and

functionalities. Based on this, a strategy is proposed for the prototype development within the RPSEA

project, which focuses on retiring the risks with fundamental development needs.

Figure 1. Example of a DC transmission and distribution system for a subsea processing plant.


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List of Abbreviations

Table 1. List of abbreviations.

Abbreviation Definition

AC alternating current

DC direct current

DGEBA bisphenol A diglycidyl ether

DGEBA-mPDA

bisphenol A diglycidyl ether and m-phenylenediamine

DI deionized

DM dry-mate

EPR ethylene propylene rubber

HVAC high voltage alternating current

HVDC high voltage direct current

LCC line commutated converter

LFAC low frequency alternating current

MoM minutes of meeting

O&G oil and gas

ROV remotely operated vehicle

SEPS the Subsea Electrical Power Standardization JIP

T&D transmission and distribution

TRL Technology Readiness Level

UDW ultra-deepwater

VSC voltage sourced converter

WM wet-mate

XLPE cross-linked polyethylene


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Definitions

Table 2. List of definitions

Term Definition

Cable termination Device fitted to the end of a cable to ensure electrical connection with other parts of the system and to maintain the insulation up to the point of connection

Connector Fully insulated termination permitting the connection and the disconnection of a cable to other equipment

Connector assembly Any assembly of wet and/or dry-mate connectors, penetrators, cable terminations, cable pigtails or jumper cables between subsea components – or any combination of these

Dry-mate connector Connector designed to be submerged in sea water, but connected/disconnected in a dry (topside/onshore) environment only (also called dry mateable connector)

Hydrostatic pressure Hydrostatic pressure corresponding to the designed water depth

Penetrator A device that enables one or several conductors to pass through a partition such as a well or a tank, and insulates the conductors from it. The means of attachment, flange or fixing device, to the partition forms part of the penetrator. Penetrators include bulkhead mounted connector assembly components. Bushing is an alternative commonly used term

Polarity reversal The event that the polarity of the DC voltage is reversed to the opposite, while the magnitude of the voltage may or may not remain the same

Qualification process A sequence of tests that are performed to verify and ratify that the design of a component is in accordance with the requirements as set out in relevant standards and customer requirements. If any relevant parameter is outside the envelope of a previously qualified connector assembly datasheet, a new qualification process shall be performed.

Rated current, I0 Maximum DC current which the connector assembly can carry continuously at maximum ambient temperature, as given by the temperature class

Rated thermal short-time current, Ith

Maximum DC current which the connector assembly withstands thermally for the rated duration (tth) immediately following the continuous operation at rated current, with maximum temperatures of ambient sea water/operational media

Rated dynamic current Id Peak value of a current that the connector assembly withstands mechanically

Subsea DC system A subsea DC electrical transmission and distribution system to supply electric power for subsea processing plant, including subsea DC transmission and subsea distribution networks connected with power conversion modules

Subsea DC transmission system Part of a subsea DC system, performing the bulk transfer of electric energy from topside or land-based power generation facilities or


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power grids to an electric distribution network located close to the subsea processing plant, using long high voltage DC cables

Subsea distribution Part of a subsea DC system located close to the subsea processing plant, performing the delivery of electric power from the transmission system to individual loads

Wet-mate connector Connector designed to be submerged in sea water, and can also be connected/disconnected in a submerged condition (also called wet mateable connector)


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2. Technical Gap for Subsea DC Connectors

2.1. Review of technical requirements

The technical requirements for subsea DC connectors are summarized in Table 3. Here the electrical

ratings are specified based on HVDC electrical system simulations analyzing the response of generic

subsea DC systems (for more details see the Technical Requirement Report [1]). The operational

requirements and the specific requirements for WM and DM connectors and penetrators, which do not

depend on the electrical voltage, are derived from SEPS SP-1001 standard for subsea AC connectors [2].

The unique technical requirements for DC connectors mainly include the following key aspects:

(a) All types of subsea DC connectors, namely, WM connectors, DM connectors, and penetrators,

are needed at transmission voltage level in a subsea DC system.

(b) The DC connectors must satisfy all the electrical requirements related to a subsea DC system,

which include not only the rated steady-state voltage and current but also transient voltages

during normal and fault conditions.

(c) The DC connectors must also satisfy the requirements related to deep sea installation and

operation. In particular, for WM connectors this means the electrical insulation in the connector

needs to be exposed to high pressure seawater during the underwater mating process.

As will be shown in the following sections, this combination of requirements makes the subsea DC

connector different from the subsea AC connectors and the high voltage components in a land-based

HVDC transmission system.

Table 3. Summary of subsea DC connector technical requirements

Operational requirements (for

WM/DM/Penetrator) Value Unit

No. of mate/de-mate operations 100 times

Maximum water depth 3000 m

External temperature range -5 to 20 deg C

Internal temperature range -5 to 60 deg C

Storage temperature -25 to 60 deg C

Service life 25 years

Maintenance need Maintenance free

Max. onshore storage time Determined by project need year

Max. subsea storage time 1 year

No. of water sealing barriers between

seawater and live parts 2

Electrical Rating (for

WM/DM/Penetrator)

Rated voltage (U0) ± 50 - 150 kV

Over-voltage (UP) 2.5xU0 kV


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Voltage polarity reversal time 1 msec

Rated current (I0) 200-1000 A

Rated dynamic current (Id) 5*I0 A

Rise time of dynamic current (td) 1 msec

Rated thermal short-time current (Ith) 15*I0 A

Duration of short circuit current (tth) 0.5 sec

Requirements for WM Connectors

Orientation during operation horizontal, vertical, tilted

Tolerance against deposits calcium deposit, marine growth, debris

Tolerance against contaminations sand, silt

Tolerance against cleaning acidic cleaning (e.g., citric acid), mechanical brushing

Requirements for DM Connectors

Mating environment

Tolerance against harsh offshore environment (e.g.,

humidity, salt)

Requirements for Penetrators

Differential pressure rating (ISO 10423

standard)

+/- 10 (with pressure compensation)

Up to 300 (no pressure compensation, depending on

water depth) bar

2.2. Technical risks and uncertainties for subsea DC connectors According to the technical requirements, the technical challenges associated with subsea DC connectors

can be divided into three types: i) those related to DC and transient voltages in DC systems; ii) those

related to subsea installation and operation; and iii) those related to the combination of DC and

transient voltages and subsea conditions, i.e., satisfying the DC electrical requirement while being

constrained by the requirements for subsea installation and operation.

Challenges associated with DC electrical operation

For a reliable insulation design, it is critical to ensure uniform electric field distribution in the insulating

structure. A fundamental difference between AC and DC insulating systems is due to the different

mechanisms governing the electric field distribution. This is a rather well-known fact (see, e.g., [3]) and

has been discussed in other RPSEA project reports (e.g., [1], [4]). For the sake of completeness a review

of this topic is included here. The basic physical principle will first be described and then the key

conclusions related to practical insulation systems will be provided.

The electric field distribution in dielectric material is described by the following relationships derived

from the Maxwell equations in dielectric medium: [5]

∇ ⋅ 𝐷 = 𝜌 (1)

∇ ⋅ (𝑗 +𝜕𝐷

𝜕𝑡) = 0 (2)


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Here 𝜌 is the charge density, 𝐷 is the electrical displacement, and 𝑗 is the current. Equations (1) and (2)

are universally true for any dielectric medium. In order to actually determine the electric field

distribution, a relationship between 𝐷, 𝑗, and electric field is needed. For the purpose of engineering

design the dielectric material can be characterized by two properties, the dielectric constant 𝜖𝑟 and the

conductivity σ, such that

𝐷 = ϵ0𝜖𝑟𝐸,

𝑗 = σ𝐸,

where 𝐸 is the electric field and ϵ0 = 8.85 × 10−12 F/m is the vacuum permittivity. Equation (2) then

becomes

∇ ⋅ (σ𝐸 + ϵ0𝜖𝑟𝜕𝐸

𝜕𝑡) = 0. (3)

The electric field is related to electrical potential V by

𝐸 = −∇𝑉.

The boundary condition for V is set by the given voltages on the metal electrodes. In addition the

electrical insulation boundary condition is also used in some situations (e.g., uniform insulating layer

with nearly infinite length), which requires the electrical current across the boundary to be zero.

Equation (3) together with the boundary conditions determines the electric field distribution in the

dielectric. This is the basic formalism used for the finite element analysis conducted for the connector

design.

In order to compare AC and DC insulation systems simplifications of equation (3) are desired. The

equation contains a first “conductive” term, 𝑗𝑐 = σ𝐸, and a second “dielectric” term, 𝑗𝑑 = ϵ0𝜖𝑟𝜕𝐸

𝜕𝑡. The

ratio between these terms is:

𝑗𝑑

𝑗𝑐= (

ϵ0𝜖𝑟

𝜎) ⋅ (

1

𝐸

𝜕𝐸

𝜕𝑡)

Roughly speaking, the first term on the right hand side of this expression represents the ratio between

the dielectric and conductive responses of the material, whereas the second term represents how fast

the electric field varies over time, which may be further characterized by a “characteristic time”, 𝜏:

𝜏 =𝐸

𝜕𝐸𝜕𝑡

Clearly, 𝜏 is simply the inverse of the angular frequency for AC sinusoidal fields. Also, 𝜏0 is defined as:

𝜏0 =𝜖0𝜖𝑟

𝜎


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the “time constant” for the material and it then follows that 𝑗𝑑/𝑗𝑐 = 𝜏0/𝜏.

AC vs. DC: resistive grading vs. capacitive grading

For the materials used as electrical insulators the dielectric constant is typically 𝜖𝑟 = 2 to 5 (see Table 4).

For solid insulating materials the conductivity is typically 𝜎 = 10−16 to 10−12S/m, while for insulating

oils this is typically 𝜎 = 10−13 to 10−10 S/m. Therefore, estimations of 𝜏0 for typical insulation materials

are:

Liquid insulation: 𝜏0 = 0.2 sec to 350 sec

Solid insulation: 𝜏0 = 20 sec to 350,000 sec(= 4 days)

For AC sinusoidal voltages at power frequency (𝑓 =60 Hz), the characteristic time for change of voltage

and electric field is

𝜏 =1

2𝜋𝑓= 0.0026 sec

Thus, under AC power frequencies, no matter in solid or liquid insulation one always has 𝜏0 ≫ 𝜏. Under

this condition, σ𝐸 ≪ ϵ0𝜖𝑟𝜕𝐸

𝜕𝑡, so equation (3) can be approximately simplified to

∇ ⋅ (𝜖𝑟𝜕𝐸

𝜕𝑡) = 0. (capacitive grading) (4)

Since in this case the electric field distribution is determined by the dielectric constant, the field is said

to follow capacitive grading.

On the other hand, in DC systems the voltage can be kept as nearly a constant for very long time, i.e.,

𝜏 ≈ ∞. Thus even for the most insulating solid material in practical use, such as the DC XLPE cable

insulation, one has 𝜏 ≫ 𝜏0, and then equation (3) can be approximately simplified to

∇ ⋅ (𝜎𝐸) = 0. (resistive grading) (5)

In this case the electric field distribution is determined by the conductivity (hence resistivity), the field is

said to follow resistive grading.

Table 4. Dielectric constant and conductivity for typical insulating materials

Insulating oil Epoxy Silicone XLPE

Conductivity (S/m) 10

-10

- 10-12

10-12

- 10-14

10-13

- 10-15

10-12

- 10-16

Dielectric constant 2 – 3.5 3 – 5 ~ 3 2.2


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It should be noted that, for AC systems both the steady-state AC voltage and the transients have very

short characteristic times (𝜏), and hence the electric field distribution always follows capacitive grading.

On the other hand, a DC system may be subjected to not only DC voltages but also different types of

transient voltages. If the transient waveform consists of a very fast component (e.g., an impulse)

superimposed on a DC bias voltage, then the electric field distribution is essentially an AC (capacitively

graded) field component superimposed on a DC (resistively graded) field component. However, if the

transient consists of a relatively slow-varying voltage, such as during the change of voltage level or the

reversal of voltage polarity, then the characteristic time 𝜏 may be similar to the time constant 𝜏0 of the

materials, and hence no simplifications like Equations (4) and (5) can be made to Equation (3). The

corresponding time-dependent electric field distribution is also drastically different from either the AC

or DC field distributions. This is further complicated by the fact that different materials in the insulation

system (e.g., oil vs. solid) could have very different time constants due to contrast between their

conductivities.

Effect of temperature, electric field, and materials compositions on DC electric fields

For the dielectric materials used in electrical insulation systems, the dielectric constant is almost

independent of the electric field and temperature, while the conductivity is highly sensitive to

temperature and also varies with electric field. For engineering purposes the conductivity can be

approximately described as

𝜎(𝐸, 𝑇) = 𝜎0 exp(𝛼𝑇 + 𝛽𝐸)

Here 𝑇 is the temperature, 𝐸 is the electric field, 𝜎0 is a constant, and 𝛼 and 𝛽 are the so-called

temperature and field coefficients, respectively. For instance, for the cross-linked polyethylene (XLPE)

insulation used in HVDC cables, the typical values are 𝛼 = 0.084/∘C and 𝛽 = 0.065 mm/kV. Thus, even

with a moderate temperature difference of 20∘C, which is common to observe for cables and cable

accessories, the conductivity in the warmer region is 5 times higher than that in the colder region. With

DC resistive grading, the continuity condition imposed by equation (5) indicates that the electric field

distribution must also be highly nonuniform. Thus, under resistive grading, a material with uniform

composition can appear to be highly nonuniform as “seen” by the electric field. Similarly, the electric

field dependence of conductivity also causes distortion of electric field distribution, but for cable

accessories its effect is typically not as significant as the temperature dependence. For instance, if the

electric field in XLPE is increased from 5 kV/mm to 10 kV/mm, the change in conductivity is less than 40

percent, which is much less than the variation of conductivity caused by typical temperature gradients.

For DC insulation systems involving only one type of dielectric material, such as those in the extruded

cables, only the temperature and field dependence of conductivity in this material need to be

considered. On the other hand, if the insulation system consists of multiple dielectric materials, then the

boundary condition of electric fields at the interfaces between these materials must also be taken into

account. This can have profound effect on the overall field distribution due to the significant contrast of

conductivities (Table 4). Consider an interface between two dielectric materials (labeled as 1 and 2), the


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tangential component of electric field (parallel to the interface) must be continuous across the interface

[5]:

𝐸1𝑡 = 𝐸2𝑡 (valid for any grading) (6)

Here the subscripts 1t and 2t denote the tangential components of fields on the two sides of the

interface. On the other hand, relationship for normal components of the electric field following

capacitive grading can be derived from equation (4):

𝜖1𝐸1𝑛 = 𝜖2𝐸2𝑛 (capacitive grading) (7)

where 1n and 2n denote the normal components of fields on the two sides of the interface, and 𝜖1 and

𝜖2 are the dielectric constants of the two materials forming the interface. On the other hand, for DC

fields following resistive grading, equation (5) leads to

𝜎1𝐸1𝑛 = 𝜎2𝐸2𝑛 (resistive grading) (8)

As shown in Table 4, the dielectric constants of different insulating materials are relatively close to each

other and lying in the range of 2 to 5. On the other hand, the conductivity can change by orders of

magnitudes across the interface. According to equation (8) this means under resistive grading the

normal component of electric field would be much lower in the medium with higher conductivity. In

particular, around solid/oil interfaces, the normal component of electric field in the oil phase is nearly

zero. Such boundary condition not only results in inhomogeneous field distribution in an insulation

system involving multiple materials, but also makes the field distribution highly sensitive to the

orientation of the interface. If the geometry is designed such that the electric field is mainly parallel to

the interface, then the field level almost does not change across the interface. If the electric field is

designed to be mainly perpendicular to the interface, then the field level could change significantly

across the interface due to conductivity contrast. In practice the latter geometry is more desirable,

because in the former case the tangential component of electric field parallel to the interface could

initiate electrical breakdown along the interfaces.

The physical mechanism behind the dramatic difference between capacitive grading (Equations 4 and 7)

and resistive grading (Equations 5 and 8) is the accumulation of charges in the dielectric material and its

effect on electric fields. Insulators are poor conductors and there are only small amount of charge

carriers moving with very low mobility. Under AC voltages, because the electric field rapidly changes its

direction, the electric charges only oscillate very slightly around their equilibrium (neutral) position. This

means at any instance the net charge density is nearly zero. On the other hand, when DC voltage is

applied for a long time, the accumulation of net charge could be significant. According to Equation (1),

the existence of net charge changes the electric field distribution, which results in the difference

between the DC resistively graded field and the AC capacitively graded field.

In summary, in DC insulation systems the electric field distribution differs from that in AC insulation

systems in the following aspects:


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1. Under DC voltages the electric field follows resistive grading (i.e., depending on conductivity of

materials), whereas under AC voltages it follows capacitive grading (i.e., depending on dielectric

constant of materials).

2. DC insulation systems may be subjected to transient voltages, during which the electric field

follows a complicated and time-dependent distribution that cannot be simply described using

resistive or capacitive grading. On the other hand, the electric field distribution follows

capacitive grading for AC insulation under both steady state AC voltages and transient voltages.

3. For DC insulation systems, because the conductivity of insulating materials strongly depends on

temperature, the electric field distribution is affected by the temperature distribution. This may

result in highly nonuniform field distribution even within the same insulating material. In

contrast, for AC insulation systems following capacitive grading, the dielectric constant is nearly

independent of temperature, and hence the electric field distribution is only determined by the

geometry and boundary conditions.

4. The dielectric constants for typical insulating materials are similar (in the range of 2 to 5),

whereas the conductivity can vary by several orders of magnitudes from one material to the

other. Therefore, for DC resistively grading the electric field could change dramatically across

interfaces between two different insulating materials, and this depends on not only the

conductivity contrast between the two materials but also the orientation of the interface with

respect to the electric field. On the other hand, the change of AC capacitively graded field across

interfaces is much less.

5. Charge accumulation under DC voltages can be significant, which have major impact on the DC

electric field distribution. On the other hand, under AC voltages the net charge in the insulation

is nearly zero.

To illustrate the difference between the electric field distributions under AC and DC voltages, consider

the example shown in Figure 2 where the typical structure of a subsea WM connector is analyzed. In

general the connector consists of cable termination chambers and a WM chamber. The cable

termination is made from a number of solid insulation materials which are combined to ensure smooth

electric field distribution around the termination of the cable, as well as forming a robust and defect-

free mechanical structure. The dielectric constant of XLPE (2.2), rubber (3.6), and epoxy (4.2) are close to

each other. Thus, under AC voltages the equipotential lines are almost smooth across the interfaces

between XLPE/rubber and rubber/epoxy, indicating little change of electric field. Under DC voltages it is

evident that the equipotential lines change their direction dramatically across the interfaces, indicating a

significant change of electric field. Even though the cable termination chamber may also contain some

oil, the oil is typically far from the stress concentrated region and hence its impact on stress distribution

is not important. The difference between AC and DC field distributions is more significant in the wet-

mate chamber, which contains a hybrid solid-liquid insulation system in order to enable the wet-mate

operation. It is seen that under AC voltages the electric field is nearly uniform across the entire structure

due to the similarity between the dielectric constants of oil (3.2) and epoxy (4.2). In contrast, under DC

the oil is hardly taking any potential drop at all due to its relatively high conductivity (about 10-11 S/m) as

compared to the solid (about 10-14 S/m). As a result the electric field is concentrated in the solid


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insulation, which causes significant stress enhancement at certain locations. This is undesirable from the

point of view of insulation design, and one of the objectives for DC connector design is to minimize such

stress enhancement.

Figure 2. Electric field distribution in a wet-mate connector under AC and DC voltages.

Challenges associated with subsea installation and operation

The subsea cable connectors must reliably operate under the rated water depth (up to 3000 meters). In

addition, high reliability must be ensured even if the installation of the connector is performed under

non-ideal environmental conditions. For instance, the mating of DM connectors must be able to be

performed under harsh offshore environments (e.g., with humidity and salt). The WM connectors must

be able to be installed remotely at the rated water depth, with the interior of the WM chamber exposed

to seawater during the mating process, and the electrical insulation must be reliably established after

the mating is finished. The challenges facing deep sea operation and installation includes not only high

pressure but also other effects related to the deep sea environment. For instance, the installation and

operation must have tolerance against corrosion, calcium deposit, marine growth, and contamination

with sand or slit. In order to meet these requirements, the overall structural design and pressure control

mechanism must ensure mechanical integrity of the connector during its entire service life. In particular,

the mechanical enclosure with its various seals must provide a reliable barrier between seawater and

the interior (electrically active) structure. Special designs are also needed to enable dry-mate or wet-

mate under required conditions.

These challenges associated with subsea installation and operations are well known and have been

extensively studied for subsea AC connectors. It should be emphasized that similar challenges exist for

subsea DC connectors and are by no means less significant when compared to the DC electrical

challenges. However, most of the structures and materials designed to address these challenges are not


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under electrical stress during operation. Therefore, the proven technologies developed to address these

problems for AC connectors can be applied to DC connectors as well. The new DC electrical design in DC

connectors may require modification and re-qualification of the mechanical enclosure, but this is

expected to be an engineering challenge rather than a fundamental development need, and hence it is

not necessary to address it in the current RPSEA project. On the other hand, certain aspects of subsea

installation will also affect the electrical performance of the connector, and these shall be discussed in

the next section.

Challenges associated with DC + subsea combination

The dielectric strength of insulating material is highly sensitive to the material’s contaminations or

defects. For DC insulation the contaminations can moreover affect the conductivity and charge

distribution in the material, which in turn affects the DC electric field distribution. Therefore, the DC

electrical insulation system typically requires highly pure materials, which is achieved by using high

purity raw materials and strictly controlled clean manufacturing processes. However, due to the

requirement of installation for subsea connectors, certain contamination may be unavoidable. For

example, in a WM connector the interior of WM chamber must be exposed to seawater during the

mating process, and afterwards the electrical insulation is re-established using specially designed

methods. An example of the WM mechanism is shown in Figure 3. In this “clean environment” design,

the two halves of the connector are first mechanically connected with seawater enclosed in the WM

chamber. The chamber is then flushed with various processing fluids and eventually filled with dielectric

oil to provide electrical insulation, and a moving metal contact is engaged to establish electrical

connection capable of carrying high current. Besides the “clean environment” design there may be other

approaches to design the WM chamber, but it is the basic requirement of underwater mating that

determines the insulation exposure to seawater before the seawater is removed or replaced after

mating is finished.

Figure 3. Example of wet-mate process with the "clean environment" design.

The uptake and diffusion of seawater in the insulation materials are illustrated in Figure 4. Seawater

contains dissolved salt (sodium chloride), as well as other minor ionic species. When the solid insulation

is exposed to seawater the water molecules and ions will diffuse into the solid and become

contaminations. During the flushing process part of the contaminants may diffuse back into the liquid


19

and be removed. Desorption of water and ions from the solid may continue after the chamber is filled

with insulating oil, resulting in the oil potentially containing moisture and ions during normal operation.

Water molecules and ions may also be trapped at the interface between the solid and liquid insulations.

The water molecules can ionize under an electric field, and together with diffused ions from the

seawater, result in the formation of positive and negative charge carriers in the insulating materials. The

existence of small amount of water or organic molecules and various ions can have multiple negative

effects on the electrical properties of the insulation system.

Figure 4. Seawater uptake and diffusion during and after wet-mate process.

Water has a dielectric constant of 80 which is much higher than most insulating materials (typically

between 2 and 5). When an insulator contains a certain amount of moisture, the dielectric constant of

the mixture is a weighted average of the dielectric constants of the two individual phases. The exact

dependence of the dielectric constant for the mixture can be rather complicated, but the range of it can

be readily estimated for different moisture contents [6]. For example, consider epoxy materials with

dielectric constant 4 and typical saturated moisture content of less than 3 percent by weight (wt%) [7]

[8]. As shown in Figure 5, the increase of dielectric constant due to moisture is less than 50 percent as

compared to the base value. The experimentally observed values for dielectric constant variation agree

with the estimation [9]. As will be discussed in the experimental section, there are epoxy composite

formulations whose saturated moisture content can be controlled to be well within 1 wt%, so that the

resultant dielectric constant variation is less than 20 percent of the base value. Charge carriers such as

ions may also affect the dielectric constant, but for dielectrics used in practical insulation systems such

an effect is significant only at very low frequencies (e.g., <1 Hz) [10]. Hence, in general the effect of

contamination in the insulation only causes limited perturbation to the dielectric constant. Thus, the

impact of contamination on field distribution is not significant for AC insulation whose electric field

distribution is determined by dielectric constant of materials.


20

Figure 5. Estimated dielectric constant of an insulator containing different amount of moisture (estimated according to [6]). The base dielectric constant without moisture is 4.

The dependence of electrical conductivity (equivalently, resistivity) on seawater uptake is more

complicated to estimate. Therefore experiments have been designed to measure such effects.

Experimental study on the effect of seawater uptake on DC insulation resistivity

Epoxy insulation samples were saturated at 90 °C in seawater (ASTM D1141-98, no heavy metal salts) for

benchmarking the maximum effect of salt water absorption on bulk resistivity. The samples were

conditioned with seawater using a setup as shown in Figure 6. Samples were nominally 0.5 mm thick

and immersed in seawater over a period of four days, and the weight increase of the sample was

periodically monitored until no further change was observed, which indicated the sample reaching

saturation.

NOTE: the resistivity is the reciprocal of conductivity, and higher conductivity means lower resistivity

(and vice versa). In the following discussions, conductivity and resistivity are both used to describe the

resistive property of the insulation.

Figure 6. Experimental setup for performing the seawater uptake experiment.


21

Experimental study on the seawater uptake rate

The rate of seawater uptake has been measured at elevated temperatures of 45 °C and 60 °C, which are

close to the actual temperature range in a connector during normal operation. Normalized water uptake

(change in sample mass, Mw, divided by final sample mass change, Mwf) for different samples is shown

in Figure 7. The absolute water uptake for the epoxy samples was between 0.40 and 0.44 wt% (by total

weight of the sample). The samples are filled with approximately 60 wt% of inorganic fillers, so relative

to the epoxy the water uptake is 1 to 1.1 wt%. The sample cross section was nominally 40 mm x 40 mm.

Figure 7. Normalized water uptake vs. square root of time at 45 °C and 60 °C. Mw: weight of absorbed seawater; Mwf: final weight of absorbed seawater (i.e., after saturation is reached). Series 1-6 represent the results of measurements performed under the two temperatures and repeated on three samples under the same experimental condition.

One-dimensional diffusion can be assumed for samples of finite cross-sectional areas but with high

aspect ratios (i.e., very thin flat samples). During the initial mass uptake, the normalized mass uptake of

seawater will be proportional to the square root of time, and can be calculated according to [11]:

𝑀𝑤(𝑡)

𝑀𝑤𝑓=

4

𝑑√𝜋√𝐷𝑡

where 𝑀𝑤(𝑡) is the total weight of absorbed seawater at time 𝑡, 𝑀𝑤𝑓 is the final weight of absorbed

seawater (i.e., after saturation is reached), 𝑑 is the thickness of sample, and 𝐷 is the diffusion coefficient.

This means that during the initial mass uptake the ratio 𝑀𝑤(𝑡)/𝑀𝑤𝑓 is proportional to √𝑡, and the

slope of the measured 𝑀𝑤(𝑡)/𝑀𝑤𝑓 vs. √𝑡 curve can be used to calculate the diffusion coefficient:

𝐷 =𝑑2𝜋

16⋅ (𝑆𝑙𝑜𝑝𝑒)2

Data for a single sample is shown in Figure 8 as an example. Fitting is performed for three different

samples for water uptake, which shows a diffusion coefficient of between 1.2x10-8 cm2/s and 1.6x10-8

cm2/s. This diffusion coefficient is consistent with data reported in the literature for epoxies (both filled

and unfilled) [12]. For instance, the diffusion coefficient of the diglycidyl ether of bisphenol A and m-


22

phenylenediamine (the DGEBA/mPDA system) increases from 3.35x10-9 cm2/s at 45 °C to 3.14x10-8 cm2/s

at 90 °C [12].

Figure 8. Normalized water uptake vs. square root of time.

A preliminary study on the pressure effect of seawater uptake has also been conducted. For the samples

saturated with seawater under ambient condition (1 bar), the final weight change after saturation were

0.4 – 0.6 wt% (data measured on eight samples saturated under temperatures of 45 °C, 60 °C, and 90 °C).

On the other hand, for the samples saturated with seawater under 1400 psi (96 bar), the final weight

change after saturation were 0.9 – 1.1 wt% (measured on four samples saturated under 90 °C). In

general, when pressure is increased the water content at saturation may either increase or decrease,

depending on the type of material [8]. Increase of diffusion coefficient and water content at saturation

has been observed in a DGEBA epoxy [13]. Further investigation of the pressure effect will be conducted

in the RPSEA project, including extending the pressure range to at least 300 bar.

Effect of seawater on DC electrical properties

Measurements of electrical conductivity were performed at room temperature (18 - 24 °C) using

conductive carbon-filled rubber electrodes. With these rubber electrodes, it is possible to perform the

seawater uptake experiment before applying the electrode (therefore avoiding any barrier effect of the

electrode), and after the samples are saturated with seawater the electrodes can be applied without

placing the sample under elevated temperature and/or vacuum (such conditions are needed to deposit

the gold or aluminum electrodes widely used for conductivity measurements) which may change the

seawater content in the sample. During the conductivity measurement, guarded electrodes were

employed to eliminate the contributions from surface conduction (following ASTM D257 standard [14],

see Figure 9). Guarded measurements were performed for three hours under an electric field of 1.1

kV/mm, and then the electric field was increased to 11 kV/mm and the measurement was continued for

another three hours. The so-called apparent resistivity, 𝜌(𝑡), was measured in this experiment, which is

defined as:

𝜌(𝑡) =𝑉

𝐼(𝑡)⋅

𝐴

𝑑,


23

where 𝑡 is the time elapsed after the voltage is applied, 𝑉 is the DC voltage (a constant), 𝐼(𝑡) is the

measured leakage current through the sample at time 𝑡, and 𝐴 and 𝑑 are the area and thickness of the

sample, respectively. The apparent resistivity describes the relationship between conduction current

and electric field, and hence it can be used in Equations (3) and (5) to calculate electric field distributions.

However, it is known that when an insulation sample is subjected to DC electric field, in general the

leakage current decays with time [10], or in other words the apparent resistivity increases with time.

Epoxy resistivity is typically reported as a short term measurement (on the order of minutes).

Representative measurements on the epoxy over a period of three hours showed that the sample

resistivity could change by up to two orders of magnitude (Figure 10). This highlights the need to

account for the time dependent behavior of the epoxy (and other solid insulation) when designing HVDC

connectors. In the design simulation this is addressed by varying the DC conductivity of material used in

the simulation model and examining the sensitivity of field distribution against such variation. On the

other hand, as indicated in Figure 10, the resistivity decreased only slightly when the electric field was

increased from 1.1 kV/mm to 11 kV/mm.

(a) (b)

Figure 9. Setup for electrical conductivity measurement. (a) The sample cell (the metal cover is removed); (b) circuit diagram for the measurement with guarded electrodes.

Figure 10. Time-dependent resistivity for connector epoxy at room temperature.

The resistivity of samples treated under different conditions was measured and summarized in Figure 11,

which shows data measured 2 minute and 180 minute (3 hour) after the DC voltage is applied. It is


24

evident that the resistivity exhibits strong sensitivity to the amount of seawater in the epoxy sample.

Compared to fresh samples, the resistivity of the epoxy samples saturated with seawater is decreased

by as much as four orders of magnitudes. Similarly, if the samples are immersed in deionized (DI) water

instead of seawater, after saturation the resistivity still reduced by more than three orders of

magnitudes. Such reduction of resistivity is due to absorption of contaminants rather than permanent

changes to the material caused by the seawater immersion. In fact, the resistivity of DI water saturated

samples can be reverted to the values for fresh (dry) samples by drying the saturated sample under

elevated temperature of 120 °C for 12 hours. In WM connectors, after exposure to seawater the WM

chamber is first flushed and then filled with oil. To study the effect of flushing, the seawater-saturated

samples were first immersed in two separate DI water baths (nominally 200 mL) and agitated for

approximately 30 seconds in each bath. They were subsequently rinsed for approximately 30 seconds

with alcohol and then immersed in alcohol for 20 hr. After 20 hr the samples were then placed in

excessive amount of oil and immediately removed for conductivity measurement. It is evident that

exposure to alcohol can “dry” the sample and increase the resistivity by about two orders of magnitudes.

In real WM connectors, after flushing the WM chamber is filled with oil in principle the amount of

seawater in the epoxy may continue to change. To study this effect, the seawater-saturated samples

were rinsed with DI water (twice in approximately 200 mL baths), alcohol (twice in approximately 200

mL baths) to simulate the flushing, and then placed in excessive amount of oil for 4 weeks, after which

the conductivity was measured again. The measured conductivity is similar to the samples flushed but

without long-term storage in oil. This suggests that flushing and reestablishing of insulation with oil can

partially recover the resistivity of the solid insulation, but apparently not fully reversing the resistivity to

its original value before being in contact with seawater.

Figure 11. Summary of electrical resistivity for samples with different conditions (fresh sample, saturated with deionized water or seawater, dried sample, seawater-saturated sample re-exposed to alcohol or oil). Measurements are a combination of 1.1 and 11 kV/mm measurements at room temperature.


25

The dramatic difference between the resistivity of pristine epoxy sample and sample saturated with

seawater is related to the substances absorbed from the seawater, which include water molecules and

possibly different types of ions dissolved in the seawater. The conductivity, 𝜎, of an insulating material

can be estimated as:

𝜎 = 𝑛𝑞𝜇,

Where the term 𝑞 = 1.6 × 10−19𝐶 is the unit charge, 𝑛 is the total concentration of charge carriers, and

𝜇 is the mobility. Neglecting the field dependence, the mobility is related by the diffusion coefficient, 𝐷,

through the Einstein relation:

𝐷 = 𝜇 ⋅𝑘𝑇

𝑞,

Where the term 𝑘 = 1.38 × 10−23m2kgs−2K−1 is the Boltzmann constant and 𝑇 is the temperature.

Taking the average measured diffusion coefficient, 𝐷 = 1.3 × 10−8cm2/s , 𝑇 = 293 𝐾 (room

temperature), 𝜎 = 10−10𝑆/𝑚 (inverse of measured resistivity for seawater-saturated sample), the total

charge carrier concentration is estimated to be:

𝑛 =𝜎𝑘𝑇

𝑞2𝐷= 1.21 × 1019 m−3.

On the other hand, assuming the density of epoxy is 𝜌 = 1.8 g/cm3, as a first approximation only

considering absorbed water (molar mass 𝑀 = 18 g/mol) and ignoring other substances such as sodium

or chlorine ions, using a saturation level of 𝑐 = 0.4 wt% (from experimental data), the total

concentration of water molecules in the epoxy, 𝑁0, can be readily estimated as:

𝑁0 =𝜌𝑐

𝑀⋅ 𝑁𝐴 = 2.34 × 1026m−3,

where 𝑁𝐴 = 6.02 × 1023 is the Avogadro constant. It means the ratio between (ionic) charge carriers

and water molecules is

𝑛

𝑁0= 5.17 × 10−8.

This means even if a very small amount of the absorbed substance becomes anionic charge carrier, the

resultant change in DC conductivity can be several orders of magnitude smaller as measured in the

experiment. It should be noted that in the above estimation all the charge carriers are assumed to have

the same mobility, and the diffusion coefficient for ions is assumed to be the same as that of the water

molecules, whereas in reality the situation is likely much more complicated. Nevertheless, this order-of-

magnitude estimation still explains that the DC electrical properties can be highly sensitive to even a

small amount of contamination.

The electrical conductivity of dry epoxy is much lower than oil, which results in highly nonuniform

distribution of DC electric field in the WM chamber. This appears to suggest that the increase of

electrical conductivity due to seawater uptake in the epoxy would improve the uniformity of field


26

distribution. This would be true if such increase of conductivity is uniform throughout the epoxy and

stable over time. However, in reality the situation is much more complicated because the distribution of

absorbed species in the epoxy is not necessarily uniform. When the epoxy is immersed in seawater,

water molecules and ions start to diffuse into the epoxy, and their average depth of penetration

depends on the diffusion coefficient D and the time of immersion. Estimation has been performed based

on the representative values of diffusion coefficient and different immersion times that may possibly

happen during WM operation. The typical thickness of epoxy in the connector ranges from several

centimeters to tens of centimeters, while the average penetration depth is on the order of millimeters

(Figure 12). This means there is a relatively thin contamination-rich layer in the epoxy which would

exhibit much higher conductivity than the dry epoxy. It should be noted that during and after flushing

the water and ion in the epoxy continue to diffuse, and under the influence of electric field it may

assume a much more complicated distribution than shown in the simplified 1-D estimation. The

corresponding conductivity distribution in the epoxy is also complicated, which further increases the

challenge of electrical stress control in the WM chamber.

Figure 12. Estimated water profile in epoxy sample, calculated based on 1-dimensional geometry. Distance: the distance from an interior point in the epoxy to the water-epoxy interface.

The effect of extra charge carriers due to seawater uptake is not only limited to the increase of DC

conductivity. Under applied DC electric field the positive and negative charge carriers will separate and

migrate towards the negative and positive electrodes, respectively, thus forming space charge regions. It

is known that this can result in significant distortion to electric field distribution [15] [16] [17]. In

addition, the bulk and surface breakdown electric fields are also affected by seawater contamination. To

evaluate such effect, the DC breakdown strength of dry epoxy sample and epoxy samples saturated with

seawater at different temperatures have been measured according to ASTM D149 standard (ramp rate

is 500 V/second). It is seen that after saturated with seawater the DC breakdown strength reduces

significantly (Figure 13). After flushing and immersion in oil, the DC breakdown strength is expected to

(partially) recover as for the case of DC resistivity. This is to be further investigated in the RPSEA project.


27

Figure 13. DC breakdown strength of epoxy samples under different conditions: fresh sample (dry); saturated with seawater under 45 °C; and saturated under seawater under 60 °C.

Summary

Although the absolute value of the water uptake appears to be small, large effects are seen on DC

properties. These effects must be considered for design and operation of subsea DC connectors.

Although full seawater saturation of the epoxy will not occur in the connector because of the carefully

designed flushing process, areas exposed to water will still absorb some amount of seawater, leading to

a concentration (and resistivity) gradient in the epoxy. Additionally, the long term properties of the solid

insulation should be considered for design, as large differences in the short term (minutes) vs. longer

term (hours) resistivity are observed.

In order to better understand the process of seawater uptake and its effect on DC insulation, additional

experimental studies are needed. For example, further measurements at various temperatures will

allow the water diffusion to be calculated for any ambient temperature (within the temperature range

expected prior to mating and during operation). Moreover, chemical analysis will reveal the type of

absorbed contaminants (e.g., water molecules, different types of ions). Additional electrical

measurements are being performed to quantify the effect of seawater uptake on surface conductivity,

space charge density, and dielectric strengths. However, from the gap analysis’ point of view, the

experimental results and analysis presented thus far clearly indicate the unique technical risks and

unknowns facing the subsea DC connectors which need to be addressed by the materials study and

prototype development carried out in this RPSEA project.

In summary, the technical challenges for subsea DC connectors include the following major aspects:

DC high voltage: voltage rating of up to ±150 kV DC is needed, which means the electrical

insulation system must be able to handle not only the DC steady state but also the possible

transient voltages generated by electrical systems operating at the rated DC voltage.

Subsea cable termination & connection: the cable connectors must be able to terminate the

high voltage cable and provide the interface for electrical and mechanical connection (mating)

which can be applied in the field.

Hybrid insulation system: for WM connectors the need for underwater mating typically requires

liquid insulation in the WM chamber. To ensure high reliability solid insulation is also needed to

Sat 60 CSat 45 CDry

180

130

80

Type

BD

(kV

/mm

)


28

provide a double barrier. This hybrid insulation system must be properly designed to handle the

complicated electrical stresses under DC and transient conditions.

Submarine operation: the connectors must be able to operate under rated high pressure (up to

300 bar, i.e., in 3000 meter water depth) and subsea environments throughout their service life.

Effect of contamination: for the connectors installed in the field, especially for WM connectors

with remotely controlled underwater mating, the contact with contaminants such as water and

salt must not compromise the long term reliability. The effects of seawater-related

contaminates on DC insulation are very different from those on AC insulation, and the level of

impact is higher for DC insulation.

As will be discussed in the next section, currently there is no existing technical solution addressing all

these challenges. However, some of the individual aspects have been studied in other existing

technologies such as subsea AC connectors and land-based HVDC transmission systems. In order to

determine the technical gap, in the next section a systematic comparison will be made between the

subsea DC connectors and relevant existing technologies, with focus on the technical challenges

outlined above.

2.3. Review of relevant technologies The key technical challenges of subsea DC connectors are compared against the state-of-the-art for

relevant existing technologies (Table 5). The choice of existing technologies was made based on the

types of challenges described in the last section. In terms of challenges with UDW subsea high voltage

cable accessories, the most relevant technology is the subsea AC connectors. However, these

connectors are not qualified for DC electrical operation. On the other hand, there have been extensive

developments for HVDC transmission and distribution systems, and the different types of components

involving HVDC insulation, such as DC cables, cable joints, cable terminations, and converter

transformers, face some common challenges as with the subsea DC connectors.

Table 5. Comparison of subsea DC connector and related existing technologies. Entries with brown color are those related to the challenges of subsea DC connectors.

Subsea AC connector

Submarine cable joint

Cable terminations

HVDC bushings

Converter Transformers

Subsea DC connector

AC or DC AC DC DC DC DC DC

Voltage (kV) WM: 36 DM: 145

500 500 800 800 WM: 150 DM: 150

Function Cable terminating & connecting

Cable joining Cable terminating

Insulating bare conductors

Winding insulation

Cable terminating & connecting

Insulation system

solid + oil All solid Solid + oil Solid + air Solid + oil Solid + oil

Operating environment

Submarine Underground or submarine

Above ground

Above ground Above ground Submarine

Contamination Exposure to seawater during mating (WM)

Clean Clean Dirty (outdoor termination)

Clean Exposure to seawater during mating


29

Subsea AC connectors

Figure 14. Examples of subsea AC connectors (GE MECON series).

Subsea AC connectors are commercially available from various vendors such as GE Oil and Gas, TE

Connectivity DEUTSCH, Hydro Group, MacArtney, POWERSEA, RMSpumptools, SEA CON Group, Siemens,

and Teledyne ODI [18]. In terms of electrical rating, qualified DM connectors are available up to at least

145kV/700A and WM connectors up to at least 36kV/900A [19] [20]. Some of these connectors have

already been installed and successfully operated in the field. For instance, the 12kV/240A three-phase

MECON wet-mate connectors have been reliably operating since 2001 in the Troll Pilot [21]. The

145kV/700A DM connectors have been installed and tested at the Ormen Lange pilot site [22]. Examples

of DM and WM AC connectors are shown in Figure 14. The size and weight of the connectors depend on

the voltage and current ratings. For instance, for the MECON DM 145/700 AC connector the weight is

140 kg per phase, and the diameter and length are 370 mm and 900 mm per phase, respectively. For the

MECON WM 36kV/500A three-phase AC connector, the weight for each half is about 400 kg. It should be

pointed out that even for subsea AC connectors the highest rating for WM connectors is 36kV, which lies

in the distribution voltage range, whereas for DM connectors (and penetrators) the highest voltage is up

to 145kV. On the other hand, because of the need for modularized DC-DC converters for DC connectors,

the transmission voltage level of up to 150kV is required for all types of connectors (WM, DM,

penetrators).

In the development and qualification of subsea AC connectors much progress has been made in terms of

UDW mechanical design and subsea installation processes. The major technical achievements made in

the AC connector development include but are not limited to [23]:

The full metal encapsulation of the electrical connecting parts by means of a metal-sealing technology that guarantees the long-term integrity of the seawater barrier;


30

The flushing process designed for transition from a highly conductive (saltwater) state to the highly insulated (oil) state for long-term high voltage operation at deep sea environment;

Electrical connections based on hydraulically actuated internal pistons for wet-mate operation;

Basic insulating materials (e.g., epoxy, silicone, oil) with proven reliability and compatibility during long-term connector operation;

Dedicated tool skid for diverless installation and maintenance, e.g., using remotely operated vehicles (ROVs).

Among the different technical requirements for subsea DC connectors (Table 3), except for the DC

electrical requirements which are unique for DC voltages, the rest of the requirements are essentially

non-electrical and can be addressed using the same technology as for AC connectors. Therefore, the

natural approach to develop subsea DC connectors is to leverage the available mechanical design for the

AC connectors and redesign a DC electrical insulation system that is compatible with the mechanical

design. Examples of qualification test steps for subsea AC connectors are shown in Figure 15.

Figure 15. Examples of qualification test steps for subsea AC connectors.

HVDC cable systems

For electric transmission between land-based locations, DC transmission and distribution (T&D) systems

offer similar advantages as for subsea oil and gas electrification, namely the capability of transmitting

high power over long distances with high efficiency. HVDC transmission and distribution systems have

been extensively developed over the past several decades: installed systems with overhead transmission

lines are currently rated up to at least 800kV DC, and those involving submarine or underground cables

are available up to at least 500 kV DC. The DC cable links in HVDC cable systems are “dry-to-dry”, i.e.,

both ends of the link are above the sea surface, even though the link may include submarine portions.

DC cables are traditionally made with “lapped” insulation. In this type of cable, insulating papers are

wrapped around the center conductor to reach a designed thickness, and then the multilayered

structure is impregnated with either low viscosity oil (oil-filled) or high viscosity compounds (mass-

impregnated). Another type of DC cable is the extruded DC cable, which consists of a single piece of

polymeric material insulation that is extruded onto the center conductor [3]. Examples of such cables

include the ABB HVDC Light® series. Compared to the cables with lapped insulation, the advantages of

extruded cables include reduced weight, lower initial and lifetime costs, simpler and easier accessories

technology, easier repair, reduced risk of flammability and propagation, and no hydrolytic/pumping

requirements. Therefore, these cables have been adopted in many major HVDC projects since their

introduction in the 1990’s, and their voltage and power ratings have also increased rapidly. In the

present R&D project, only cable connectors for extruded cables will be studied. One of the major


31

reasons for the late introduction of the extruded DC cables as compared to their AC counterparts

(introduced around the 1960’s) is because of the problem of space charges. A special grade of XLPE

insulation composition had to be developed to meet the reliability requirement under DC voltages.

Currently, the existing extruded DC cables are predominantly made of the “Superclean” XLPE resin. So

far these extruded DC cables are only used for voltage-sourced converter (VSC) systems in which the

system voltage is maintained at the same polarity, while the line-commutated convert (LCC) systems

require DC cables with lapped insulation, which have been proven to be highly reliable even under

polarity reversal. There have been recent reports of special nano-filled XLPE HVDC cables which can be

used for LCC systems; thus far only one 250kV DC cable link with relatively short length (44km,

submarine) has been installed. It has been operational since 2012 [24].

Cable has very simple geometric structure, and because of economic considerations there is stringent

limit for the size of cable. Thus to improve the performance of DC cables, most of the efforts are

devoted to the development of DC insulation material, either by modifying the chemical structure of the

insulating material or by introducing special fillers [3]. An example of DC cable insulation development is

shown in Figure 16.

(a)

(b)

Figure 16. Development of a low cost DC cable insulation material based on nanoclay reinforced ethylene-propylene rubber (EPR). (a) Insulation material, with EPR base resin, nanoclay fillers, and compounded insulation resin exhibiting layered structure. (b) Space charge profile in the state-of-the-art Superclean

TM DC XLPE insulation and the nanoclay-EPR insulation,

showing that very low space charge density can be achieved in nanoclay-EPR without needing the (costly) degassing step. Work performed by GE Global Research, supported by ARPA-E Award No. DE-AR0000231.

As of today, extruded DC XLPE cables are commercially available with at least 320kV DC voltage rating

and ampacity of as high as 3000 A per conductor. The corresponding DC cable accessories, including

cable joints and cable terminations, are also available up to the same voltage and current levels.


32

Cable joints are used to electrically connect two segments of cables. For HVDC T&D systems, the

components related to submarine applications are submarine cable joint, e.g., factory joints which are

applied during manufacturing of long cable links before armoring is applied, and field or installation

joints which are used during installation [25]. To install submarine cables, typically a very long

continuous cable with submarine packaging is loaded to a cable laying vessel, which is then transported

to the designated location and deployed to the seabed. Because of manufacturing restrictions and

logistic limits (e.g., size of laying vessel), multiple sections of cable need to be spliced using cable joints

and tightly sealed with subsea packaging. In terms of structure and function, the submarine cable joints

are used to connect two pieces of cables rather than terminating the cable. Unlike connectors, the joints

do not need to be disconnected after installation. These allow for compact and relatively simple design.

Submarine cable joints also utilize an all-solid insulation system. A typical structure of a cable joint is

shown in Figure 17a.

Cable terminations are used to terminate the uniform and continuous cable geometry and connect the

center conductor with other components in the HVDC system, such as overhead transmission lines,

transformers, or gas insulated switchgears. Thus, the HVDC cable terminating function is common for

these existing cable terminations and subsea DC connectors. However, unlike cable joints, which are

found in submarine cable links, in HVDC T&D systems only land-based terminations are needed. Thus,

the requirement for mechanical packaging (e.g., pressure tolerance, sealing, DM/WM, and pressure

barrier) compared to subsea connectors is much less stringent for these cable terminations. The HVDC

cable terminations may employ either all-solid or solid-oil hybrid insulation system. A typical structure of

a cable termination is shown in Figure 17b, and the picture of a real HVDC cable termination is found in

Figure 17c.

Subsea DC cable connectors can be regarded as special DC cable terminations that are suitable for ultra-

deepwater (UDW) subsea operation. The general challenges with DC electrical design are essentially the

same for the HVDC cable systems and subsea DC connectors. The needs for dedicated development of

DC cable accessories and their difference from AC cable accessories are identified during the

development of HVDC cable systems. The general design methodology for HVDC cable accessories, as

well as the fundamental understanding achieved in the study of HVDC cable systems, serves as a useful

reference for the subsea DC connectors. For instance, they include the general approach of resistive

grading in DC cable accessories, the understanding of space charge accumulation in the insulation and

along interfaces, and the possible use of nonlinear stress grading materials to handle DC and transient

stresses. However, it should be pointed out that there is no standardized design practice for HVDC cable

accessories, and different vendors may choose to use different approaches. The design also depends on

the type of application, for instance the outdoor air termination and indoor termination for gas-filled or

oil-filled instruments are very different. Furthermore, the detailed design used by different vendors is

typically highly proprietary.


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(a)

(b) (c)

Figure 17. Examples of HVDC cable accessories. (a) Illustration of an HVDC cable joint; (b) Illustration of an HVDC cable termination; (c) Photo of HVDC cable termination used in the Baltic cable project (Source: Wikimedia http://en.wikipedia.org/wiki/HVDC_converter_station#mediaviewer/File:BalticCableHerrenwyk.jpg)

The differences between HVDC cable systems and subsea connectors also lie in their types of insulating

materials. The requirement for materials compatibility is more stringent for subsea connectors than for

cable systems. For instance, the impact of seawater must be taken into account when selecting the type

of insulation oil in subsea connectors. The solid insulating materials, such as epoxy and rubber, must

then be selected to ensure compatibility with the oil. The resulting insulation materials system can have

different DC electrical properties from those used for onshore terminations. In addition, the impact of

seawater and the flushing process on short-term and long-term DC electrical performances is highly

important for subsea WM DC connectors, yet this is not addressed in the design of land-based DC cable

terminations. This affects not only the connector design but also the qualification test method.

Finally, but not least important, it is much more difficult to retrieve and replace a subsea connector in

ultra-deepwater in the case of failure as compared to the HVDC cable terminations situated in

substations or platforms. As a result the requirement for reliability is expected to be much more

stringent for subsea DC connectors than for cable terminations, which necessitates a connector design

with a larger safety margin and qualification test methods aimed at higher reliability.

In addition to the design of the cable accessories, the existing qualification test methods for HVDC cable

systems also serve as the starting point to define testing methods for subsea DC connectors. For

example, the CIGRE TB496 document titled “Recommendations for Testing DC Extruded Cable Systems

for Power Transmission at a Rated Voltage up to 500 kV” is dedicated to the testing of extruded HVDC

cables [26] [27]. The key acceleration method in this test recommendation is to apply excessive voltage

levels over a prolonged duration and under different load conditions (full load, zero load, load cycle).

The acceleration factor has been recommended based on the experience for DC XLPE cables.


34

HVDC converter transformers

Converter transformers are used in HVDC converter stations. These transformers are subjected to not

only AC voltages but also very high HVDC bias. For example, converter transformers with as high as

800kV DC rating have been developed for major HVDC transmission projects. In general a paper-oil

hybrid insulation system is used to isolate the high voltage windings and lead conductors from the low

voltage winding and grounded enclosure. From the insulation design’s point view the most challenging

sub-components in an HVDC converter transformer are the winding insulation and the transformer

bushing.

Like the WM connectors, the HVDC converter transformers also employ oil-solid hybrid insulation

system. While the solid serves as the main insulation under DC, the oil is indispensable in both cases. For

converter transformer’s oil is needed for cooling purposes, while for WM connector’s oil is needed to

displace seawater and maintain electrical insulation. Certain common features are shared by all such

hybrid insulation systems. For instance, the conductivity of oil is typically one to two orders of

magnitude higher than solids, and hence under DC steady state the electrical stress almost completely

lies in the solid insulation. Correspondingly, there are significant surface charges accumulated at the oil-

solid interfaces. Under transient voltages this would result in a highly complicated electric field

distribution. In addition, it is known that strong and non-uniform DC electric fields can induce fluid

motion, which in turn can cause charge accumulation on the oil-solid interfaces and may result in

surface discharges (the “flow electrification” phenomenon). Special numerical model and experimental

methods have been developed over the years to study the electric field distribution and charge motion

in the oil-solid insulation system, which can be leveraged for this study of subsea DC connectors,

especially for the WM connectors.

There are obvious differences between the HVDC converter transformers and the subsea DC connectors.

First of all, the converter transformers are not cable accessories, and hence their overall structure and

design methodology are very different. In addition, the converter transformers are designed for land-

based applications, and hence the subsea aspects are not addressed. The insulation materials used in

converter transformers are also different from the subsea connectors. For instance, the converter

transformers almost exclusively use Kraft paper and pressboard as the solid insulation, while the subsea

connectors typically use epoxy, rubber, and sometimes ceramics. The converter transformers use

mineral transformer oil as the liquid dielectrics, while this is not necessarily the best choice for subsea

connectors. Therefore, while the general approach for exploring oil-solid hybrid insulation system can be

leveraged, the actual data for the converter transformer insulation are not directly applicable to subsea

DC connectors.

An example of HVDC transformer development is shown in Figure 18.


35

(a)

(b) (c)

Figure 18. Development of a 300kVDC, 20kHz HVDC transformer. (a) a scaled-down prototype with 300kV DC and 250 kVA rating; (b) electrical stress distribution in the paper-oil hybrid insulation, 2 seconds after voltage is turned on, showing electrical stress in both oil and paper due to capacitive grading; (c) electrical stress distribution at 6000 seconds after voltage is turned on, showing electrical stress almost completely confined in paper due to DC resistive grading. Work performed at GE Global Research with support from ARPA-E under Award No. DE-AR0000224.

Indoor and outdoor HVDC bushings

A common feature of the HVDC insulation components mentioned thus far is that the component is in a

clean state and during normal operation is protected by the packaging so that the external environment

does not introduce contamination to the interior electrical structure. In fact, special manufacturing

methods are often employed to ensure cleanliness, such as the use of clean rooms and drying under

elevated temperature and vacuum. On the other extreme, the HVDC bushings are designed for

operation under “dirty” environments. The bushings are normally used to insulate high voltage bare

conductors from the earthed conductive barrier and allow the high voltage conductor to safely pass

through the latter. The surface of the bushing is exposed to the ambient environment, and so it must

have tolerance against environmental factors such as moisture, dust, and salt, depending on the type of

operating environment. The requirement is especially stringent for outdoor bushings, as for example

these must safely operate under rainy conditions. Special insulating materials have been developed over

the years to achieve desirable surface conditions and maximize the surface breakdown field. In order to

provide reliable DC electrical insulation under such “dirty” conditions, the total surface creep length


36

between the high voltage and ground conductors must be sufficiently large. For HVDC outdoor

insulation this creep length is in the range of 20 to 40 mm/kV [28], and this is realized by using the skirt

geometry (Figure 19). Simple estimation shows that even if the lower end of the range is used as a

reference (20 mm/kV), a 50kV DC connector would require 1 meter of total creep distance, which in

practice is difficult to achieve within the mechanical enclosure of a subsea connector.

In the WM connector, even though the contamination level in the insulation may be higher than in the

“clean” type land-based HVDC components, because of the specially designed WM procedure, such as

the flushing process, the operating condition is much less harsh as compared to the outdoor HVDC

bushings. Thus as an extreme case the learning from HVDC bushings provides understanding on the

effect of contaminations on DC electrical properties, but it is not likely that the actual design concepts of

these bushings will be leveraged for the subsea DC connectors.

Figure 19. Examples of high voltage bushings. Left: typical structure of a bushing showing the skirt structure; Right: a large 600 kV DC wall bushing.

2.4. Summary of technical gaps Based on the analysis of technical challenges for the subsea DC connectors and the review of relevant

existing technologies, the technical gaps can be identified as the technical challenges that are not

addressed in any of the existing technologies. These include:

1) DC electrical insulation with subsea-compatible packaging: the subsea DC connector consists of

cable terminations and connecting interfaces which must operate under deep sea conditions.

Similar components have been developed for land-based applications. However, requirements

for subsea installation and operation place restrictions on the size and shape of the electrical

insulation system, as well as the selection of compatible materials. The subsea-compatible HVDC

insulation system must be developed for the connector.

2) DC insulation under the influence of contaminants: the effect of contamination on DC electrical

properties does not need to be considered for land-based HVDC components whose insulation

stays under “clean” condition. On the other hand, the methods to provide robustness against

heavy contamination are not likely to be feasible for subsea connectors for HVDC bushing used

for extreme “dirty” environments. Thus, a special subsea-compatible DC insulation system must


37

be developed to operate reliably under the possible influences of contaminations existing in

WM connectors.

3) Ultra-high reliability: Compared to land-based HVDC components, it is much more difficult to

inspect, retrieve, and repair/replace subsea connectors. These connectors in fact are normally

required to be maintenance-free within its service cycle (Figure 19). Thus, the level of reliability

needed for subsea DC connectors is expected to be higher than their land-based counterparts.

The first and the third technical gaps exist for all types of connectors (DM, WM, penetrator) while the

second one only exists for WM connectors. On the other hand, high voltage WM connectors are

critically needed in subsea DC systems to enable modularized subsea DC power conversion. Thus, in

terms of closing technical gaps, the priority is given to WM connectors.

3. Gap-Closing Strategy in the RPSEA Project

In order to close the technical gap for subsea DC connectors and reach the stage of deployable

connector products, the following development efforts are needed:

1) Basic study: the influence of subsea environment on the DC insulation system must be

understood. For instance, this would include the absorption and diffusion of water and ions

during the wet-mate process. The electrical response of the insulation under DC voltages also

needs to be studied, which includes the influence of contaminations. Such electrical responses

include steady state electric field distribution, the dynamics of electric field during voltage

transients, space charge accumulation, and the degradation and electrical breakdown of

insulation. The basic study also includes the exploration of new materials that can be used for

subsea DC connectors. Typically the development and qualification of completely new insulation

systems requires very long time (several years). On the other hand, modification of existing

materials system, such as by adding functional fillers or introducing special surface coatings,

may be a more viable approach for subsea DC connector development.

2) Design simulation: novel design concepts need to be proposed and numerically evaluated to

address the need for electrical insulation in subsea DC connectors. The design must ensure

relatively uniform electrical stress distribution in the connector and also provide robustness

against possible variations in materials properties due to, e.g., temperature change, materials

degradation, and/or contaminations. Due to the uniqueness of subsea DC connectors,

innovative design concepts are needed to effectively provide DC electrical insulation within the

subsea-compatible mechanical enclosure. The learning from the basic study shall be utilized in

the design.

3) Validation of design concept: the design concept should be validated by fabricating a prototype

mock-up unit and testing it using specially arranged methods to examine its electrical

performance under the influence of relevant subsea conditions. This “electrical prototype mock-

up” aims at evaluating the new electrical design rather than providing a fully functioning


38

connector for product qualification. Therefore, simplifications can be made on the structures

that are mechanically important but not under electrical stress (Figure 20). The design validation

is the central task in this RPSEA project.

4) Product development and qualification: additional engineering development is needed to

produce fully functioning connector products after the electrical design concept is validated,

including the interior electrical structure and all the mechanical structures needed for a subsea

connector. The fully functioning connectors must also be qualified using the complete

qualification test cycle with DC electrical tests as well as subsea-related tests (expected to be

similar to those for AC connectors, see for example [2]).

(a) (b)

Figure 20. The comparison of (a) an electrical prototype mock-up of a WM connector with complete electrical insulation structure but simplified mechanical structure, and (b) a fully functioning WM connector with complete mechanical structure for subsea mating and continuous operation under high pressure.

As indicated by the technical requirement (Table 3), in order to satisfy the power requirement for future

offshore oil and gas fields, the highest voltage needed for subsea DC connectors is estimated to be ±150

kV DC. Connectors with lower voltage ratings (e.g., 50kV) may still satisfy the need for fields with lower

power demand. The question is whether the RPSEA project should adopt a “one-step” approach, i.e.,

directly attempting to develop prototypes with high voltage rating (e.g., 100 kV or 150 kV DC) that can

satisfy the need of most future subsea DC systems; or a “two-step” approach, i.e., first retire the critical

technical risks using a prototype at entry-level DC voltages (e.g., 50kV DC) within the RPSEA project, and

then scaling up the voltage in a subsequent development effort. The choice between the two

approaches should be made based on the complexity of prototype development at different voltage

ratings, versus the learning that can be acquired from its development. A preliminary engineering design

has been conducted for this purpose in the project to estimate the size of prototypes at different

voltage ratings. The key results from this preliminary design will first be presented in the rest of this

section, and the challenges and benefits of prototyping at different voltages will be discussed, followed

by a proposal for the gap closing strategy in the RPSEA project.

3.1. Preliminary engineering design The method for the preliminary engineering design is illustrated in Figure 21. The electrical insulation

system in a WM connector can be divided into cable termination chambers and the WM chamber. The

electrical stress distribution under DC voltages in a typical subsea connector structure is shown in Figure

21, where the contours represent equipotential lines, and denser contours indicate higher electric fields.

It is evident that electrical stress concentration mainly happens at certain locations: a) on solid

insulation in the WM chamber; b) around the curved metal conductor in termination chamber; c) on the

electric field deflector in the termination area; and d) in the solid/oil/seal interface region in the WM


39

chamber. In terms of DC insulation design the stress concentration at these focused areas shall be

minimized.

Figure 21. Method of preliminary engineering design.

The electrical stress concentration depends on certain critical geometric parameters for each of the

focused area of design optimization. The main objective for the conductor profile in the cable

termination chamber is to reduce the electrical stress around the junction between cable conductor,

cable insulation, and connector insulation. Thus, the conductor is designed to form a “Faraday cage”

structure so that the junction is shielded within it. The effectiveness of shielding depends on the length

(L) and height (W) of the Faraday cage (Figure 22a, b). The effectiveness of shielding can be most easily

visualized by comparing the stress distributions for an optimized and a non-optimized design (Figure

22c,d).

Figure 22. Design optimization for the conductor (“Faraday cage”) in the cable termination chamber. (a) The structure around the Faraday cage; (b) The dependence of maximum tangential field along the surface of cable insulation on the shape of Faraday cage; (c) Distribution of equipotential lines for an optimized design showing effective shielding; (d) Distribution of equipotential lines for a non-optimized design showing incomplete shielding.


40

The high voltage cable has a semiconductive polymer layer (“semicon”) outside the cable insulation

layer. The field deflector is used to prevent electrical stress concentration when the cable’s

semiconductive layer is terminated, and is typically also made of a semiconductive polymer. It should be

noted that these materials are called “semiconductive” because their conductivity, around 1 S/m, is

much lower than that of metals. However, these materials can be regarded as good conductors over the

frequencies encountered in the DC connector (i.e., no electric field can penetrate into these

semiconductive materials, and the electric field can only have normal component at the boundary of

these materials). The effectiveness of the field deflector to control the electrical stress depends on the

profile of its critical surface facing the cable (Figure 23a). The shape of this surface can be described

using a quadratic polynomial: 𝑦 = 𝑎𝑥 + 𝑏𝑥2, where 𝑥 and 𝑦 are the horizontal and vertical coordinates.

In addition to the parameters 𝑎 and 𝑏, another important parameter is the total length of the field

deflector, 𝐿 (measured in the 𝑥-direction). The dependence of maximum tangential electric field along

the surface of cable insulation, which is known to be the most critical electrical stress to minimize in

cable terminations, is shown in Figure 23b. It is seen that the maximum tangential field is sensitive to 𝑏

and 𝐿 but insensitive to 𝑎. Moreover, once 𝑏 and 𝐿 are increased to certain level, any further increase

does not result in significant reduction in electrical stress. This suggests an optimal region of 𝑏 and 𝐿

values for the connector design. The electrical stress distributions for optimized and non-optimized

deflectors are compared in Figure 23c and Figure 23d. The distribution of equipotential lines along the

cable insulation surface is uniform for the optimized design, which indicates a uniform and low

tangential electric field distribution. The equipotential lines are much denser in certain regions along the

same surface for the non-optimized design, which indicates stress concentration in these regions.

Figure 23. Design optimization for the field deflector in the cable termination chamber. (a) The structure around the field deflector with the critical surface indicated and approximated using quadratic polynomial; (b) The dependence of maximum tangential field along the surface of cable insulation on the shape of critical surface on the field deflector; (c) Distribution of equipotential lines for an optimized design; (d) Distribution of equipotential lines for a non-optimized design.


41

The situation in the WM chamber is different from the cable termination due to the hybrid solid-oil

insulation. The dependence of the electrical stress in the solid insulation (e.g., epoxy) on the geometric

parameters of the WM chamber is shown in Figure 24. There are two types of solids in the WM chamber,

one used to insulate conductor pins (A) and the other for insulating the movable shuttle piston (B). The

result (Figure 24c,d) indicates that the electrical stress in epoxy A only depends on its own thickness,

and the same is true for epoxy B. Moreover, the electrical stresses in the epoxies are nearly independent

of the interface length, L.

Figure 24. Design optimization for the WM chamber, with focus on the electric field in the solid insulation. (a) The structure of WM chamber; (b) DC stress distribution in WM chamber; (c) Dependence of maximum electrical stress in epoxy A on geometric parameters; (d) Dependence of maximum electrical stress in epoxy B on geometric parameters.

The tangential electric field along the solid/oil interface is another important parameter in the design of

WM chamber (Figure 25a). The dependence of the tangential field on the interface lengths and the

epoxy thickness are shown in Figure 25b. It is evident that the length of interface beyond the seal has

the most significant impact on stress level, while the length of interface between the seal and the

conductor has less significant effect. On the other hand, as long as the epoxy insulation is not too thin,

the effect of its thickness is also insignificant.


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Figure 25. Design optimization for the WM chamber, with focus on the electric field along the solid-liquid interfaces. (a) The structure of WM chamber; (b) Dependence of maximum interfacial electrical stress on geometric parameters; (c) Electrical stress distribution with optimized design; (d) Electrical stress distribution with non-optimized design.

The design simulation performed for the focused areas (Figure 22 to Figure 25) provides guidance for

choosing the optimal geometric parameters when designing the complete electrical insulation structure

in the connector. The preliminary engineering designs for 50kV and 100kV DC connectors are proposed

based on these results ( Figure 26). Here the two designs are assumed to have the same current rating

(500A), therefore the power for the 100kV design would be twice of that for the 50 kV design. The

purpose of the comparison is to evaluate the dependence of engineering challenges on voltage rating to

better guide the RPSEA project, rather than comparing different options to reach the same power

demand for actual subsea oil and gas projects. The overall sizes of these two designs are compared in

Figure 26a. Here the basis of the comparison is that in both designs the maximum electrical stresses at

all the critical locations are controlled to be the same, as shown in Figure 26b.


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(a) (b)

Figure 26. Preliminary engineering designs for WM connectors with 50kVDC and 100kVDC ratings. The current rating for both designs is 500 A. (a) Overall size comparison between the two designs; (b) Zoomed-in view showing that similar electrical stress levels are achieved in the two designs.

3.2. Gap-closing strategy for RPSEA project The fabrication of connectors requires stringent process control and quality assurance. The testing of

the connectors also involves special test setups. Thus, even for the development of electrical prototype

mock-ups, in addition to the fundamental technical challenges for subsea DC connectors, the

engineering risks cannot be overlooked. In particular these challenges and risks may depend on the

voltage rating, as summarized in Table 6. The challenges have been divided into fundamental

development need and engineering risks. Level of engineering risk has been further rated from low to

high considering the time and resource of the RPSEA project. The assessment of the challenges is done

for three voltage levels: 50kV, 100kV, and 150kV.

The diameter, length, and approximate weight of the prototypes can be estimated from the preliminary

engineering design. It is evident that as the voltage increases the inner diameter (I.D.), i.e., the

maximum diameter of the electrical insulation, increases dramatically. Fabricating insulated part with

larger diameters places additional processing challenges. For example, the cure shrinkage and internal

stress build-up problems become more challenging at larger sizes, and inadequate control of these

factors could lead to imprecise shape/dimension, defects, and/or cracking. The process control is an

engineering challenge for any connectors rather than being a new risk for subsea DC connectors, and


44

there are well-established methodologies to improve the process. However, this would consume

considerable project time, and if not properly and thoroughly addressed this may lead to defective

prototypes. Among the designs with the three voltage levels, the I.D. for the 50kV design is within the

I.D. envelope for the majority of the GE MECON subsea AC connectors, whereas for 150kV the I.D.

exceeds the largest MECON insulators produced so far. Thus, from a prototyping challenge’s point of

view it is more desirable to adopt a 50kV design, which allows more experimentation of innovative

geometric designs and materials selections within the same overall diameter (i.e., focusing on the DC-

related electrical risks), instead of focusing the effort on increasing the diameter (which is not a new

challenge for DC). Compared to the 50kV design, the additional time needed to develop prototypes at

100kV and 150kV ratings are estimated to be six months and nine months, respectively, based on GE’s

previous prototyping experiences.

The length of the prototypes does not increase as dramatically as the diameter for higher voltage ratings.

In terms of design validation in the RPSEA project the major engineering challenge with long prototypes

is mainly associated with the size of electrical test setup, conditioning of the prototype to simulate

subsea environments, and the transportation of prototypes.

Table 6. The complexity of electrical prototype mock-up development versus the voltage rating. Color coding: Green - Low engineering risk; orange - moderate engineering risk; red - high engineering risk; Blue - DC connector fundamental risk

50 kV 100 kV 150 kV Comment

Inner diameter 190 mm 370 mm 550 mm • Large I.D. requires new mechanical enclosures • More challenging to fabricate larger

prototypes; general engineering challenge rather than DC-specific risk

Length 1450 mm 1900 mm 2350 mm

Approximate weight 200 kg 360 kg 700 kg

Additional time for prototyping (50kV as baseline)

0 month 6 month 9 months

Max DC test voltage 93 kV 185 kV 278 kV • Estimated according to CIGRE TB496 • 125 kV level impulse tester being assembled at

GE GR • High voltage impulse testing requires

dedicated test projects at HV test facilities, impact to timing

Peak Impulse test voltage

125 kV 250 kV 375 kV

Uncertainty related to DC stress control

High High High • Fundamental risk to subsea DC connectors

Uncertainty related to wet-mate effect

High High High

Another major impact of prototype voltage ratings on the RPSEA project is the required test voltages for

these prototypes. According to the CIGRE TB496 test recommendation for DC cable systems the test

should at least include load cycle testing at DC voltage equaling to 1.85 times of the rated DC voltage, as

well as impulse tests whose peak voltage was determined to be 2.5 times that of the rated DC voltage


45

from the technical requirement study [1]. The DC and impulse testing require assembling dedicated test

setups, including a cable loop connected to the connector, DC and impulse voltage generators, current

transformers (for generating load current), and various electrical and temperature sensors, as shown in

Figure 27. With 50kV rated DC voltage, these tests can be performed at GE (A special impulse generator

will be made for the tests to provide peak impulse voltage of up to 125 kV.). For higher voltages, and in

particular higher impulse voltages, the tests need to be performed at dedicated high voltage testing

facilities (e.g., EPRI, NEETRAC). Since the tests are not simple materials/component tests but rather

require the assembly of a special test system (Figure 27), dedicated testing projects are likely needed,

which can significantly lengthen the schedule of the project. Testing at external facilities will also

compromise the flexibility of changing the test configurations and hence may reduce the learning to be

obtained from the test.

Finally, the technical gaps associated with subsea DC connectors, such as the uncertainty of handling the

DC electrical stress in a subsea-compatible packaging, and the uncertainty of the effect of seawater on

WM connector insulation, are due to the inherent difference between AC and DC electric fields and the

effect of contaminants on DC electrical properties. Thus, similar challenges exist for all voltage levels and

the dependence on voltage is not significant.

Figure 27. Outline of an HVDC electrical test setup for testing the subsea DC connectors.

Based on the complexity analysis, a technical gap-closing strategy has been proposed for the RPSEA

project. The suggested approach is to develop an electrical prototype mock-up at 50kV DC rating. As

described in the Statement of Work, the fabricated prototype will first go through “dry” condition tests,

i.e., electrical tests without any involvement of seawater, in order to evaluate its DC electrical

performance. Then the prototype will be subjected to “wet” tests, in which the interior insulating

structure will be first conditioned using high pressure seawater under simulated deep sea environment,

followed by flushing using various processing liquids, before being electrically tested. The wet test is a

critical part of the project, since it addresses the problem of seawater contamination effects on DC

insulation.

An alternative (but not a recommended) approach is to develop prototype with 100kV rating. Certainly,

in future offshore oil and gas projects voltages equal to or even higher than 100kV are needed. However,

due to the engineering challenge of fabricating larger prototypes, longer time is expected to finish the

prototyping task. In addition the risk with prototyping also increases considerably. Because of the limit


46

on overall project duration (project ending no later than Sep 30, 2016), this approach leaves much less

time for prototype testing. Since electrical tests at higher voltages also demand longer time, only dry

condition tests can be accomplished in the project and the wet condition tests will need to be discarded.

Thus, the alternative approach would devote much more of the project effort to engineering challenges,

while neglecting the critical tasks aimed at retiring the fundamental technical challenges associated with

subsea DC connectors as compared to existing subsea AC connectors and land-based HVDC components,

which is the main objective of the project. Therefore, this approach is not recommended for the project.

Figure 28. Proposed gap-closing strategy for RPSEA project, compared to an alternative (but not preferred) approach

If, as recommended, the RPSEA project only includes the prototype fabrication and validation tests with

50kV DC rating, a remaining question is whether the lessons learnt can be applied for higher voltages,

i.e., up to 150kV DC. As explained earlier, the fundamental issues of DC insulation, such as DC stress

grading and DC electrical properties under the influence of subsea-related contamination, are due to the

nature of DC voltages and materials properties, rather than driven by specific voltage levels. However,

the quantitative dependence of such properties may indeed change with voltage level. To illustrate this

point, an example from the study of HVDC converter transformer insulation is shown in Figure 29a

(according to [29]). These converters are rated to as high as 800kV DC, and during the validation of

different design concepts it is difficult to construct full-sized transformer prototypes. On the other hand,

simply testing small material samples is not adequate to guide the design for higher voltage ratings

requiring larger insulation dimensions. For instance, the dependence of dielectric breakdown voltage for

oil-pressboard insulation is not a linear relationship, which means the breakdown electric field will

depend on the size of insulation. As shown in Figure 29a, generally the breakdown voltage increases at


47

less than a linear relationship, which is related to the volume effect of breakdown field, i.e., the

statistical probability of breakdown increases with increased volume. Moreover, such a “scale-up

relationship” depends on the geometry of insulation. The scale-up relationship can be determined by

measuring the breakdown strength for simplified models, such as Models A to C in Figure 29a, which

represent typical geometric features in the converter transformer insulation system. This was proven to

be an effective method to provide reliable inputs for the ultra-high voltage HVDC converter transformer

design.

A similar method is proposed for the subsea DC connector development in the RPSEA project. More

specifically, the critical regions in a DC connector that will affect its DC electrical performance will first

be identified. For instance, as described in the preliminary design analysis under Section 3.1 of this

report, these critical regions would include the field deflector and “Faraday cage” in the cable

termination, concentric epoxy/oil insulation on a center conductor, and the complex epoxy-oil-seal

interface structure in the WM chamber. Simplified geometric models will then be designed to represent

these critical structures, in the sense that the DC electrical stress distribution in the simplified geometric

models will be similar to those in a complete connector. This is to be validated using numerical

simulation. Examples of such simplified geometries mimicking the critical structures in the WM chamber

can be found in Figure 29b. Measuring the electrical properties of these geometries with different sizes

will provide the scale-up relationship which is critically needed to design connectors at higher DC voltage

ratings. The most important electrical parameter is the breakdown strength of these structures.

Examples of other relevant electrical measurements include electric field sensing and bulk/surface

conductivity measurements. These measurements will be performed aiming at providing inputs for up

to 150kV DC connector design.

Comparing to the prototype-level development and qualification tests such as those to be performed at

50kV level in this project, the “simplified geometry test” is different in two aspects. First of all, the

geometry of the test samples is simpler than those of a complete connector, and hence the fabrication

time and risk for making larger components, which are needed for higher voltage ratings, can be

considerably reduced. Secondly, the major test of these simplified geometric models is the electrical

breakdown test, which is a short term test (on the order of days) whereas the benchtop qualification

test for prototypes involves comprehensive test steps taking longer time (on the order of months) and

aiming at evaluating the long-term reliability of the connector with accelerated aging. The breakdown

tests can be readily performed within GE or at other test service providers, whereas performing months-

long qualification tests at such facilities would require significantly more engineering effort (e.g., long

preparation time, high cost, uncertainty with test system availability). On the other hand, the

breakdown test can provide the relationship between dielectric strength and the dimension and shape

of the insulation system, which is the most critical information needed for developing higher voltage

connectors; whereas the effectiveness of stress control and the long term aging mechanism are

expected to be insensitive to the dimension of insulation, and hence lessons learnt from testing the 50

kV prototype can be leveraged for higher voltage designs.


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(a)

(b)

Figure 29. Investigation on the “scale-up relationship” between critical DC electrical properties and the voltage level (and hence size) of insulation material. (a) The dependence of oil/pressboard interface breakdown strengths on the total creep distance for different geometric configurations. [29] Model A: pressboard with vertical boundary is immersed in oil and sandwiched between electrodes; Model B: similar to A, but the oil volume is intercepted by a thinner pressboard; Model C: multiple thin pressboards, overlapping in the lateral direction, but with oil gap open in the vertical direction. (b) Possible model geometries to study scale-up relationship for subsea DC connectors.

The detailed plan for the technical development in Phase 2 of this RPSEA project is being revised based

on the comments received at the Second Open Industrial Workshop, which was conducted on March 25,

2015. The Minutes of Meeting (MoM) of the workshop are attached to the present report as an

appendix.

With the proposed gap-closing strategy, the current Technical Readiness Level (TRL) (defined according

to API RP 17N [30]) and expected TRL at the end of project are listed in

Table 7.


49

Table 7. Technical readiness levels, current status and expected level for end of RPSEA project.

Item Current TRL Target TRL Comment

Cable termination 1 3 Require test on RPSEA prototype

Conductors 4 4 Technology implemented in MECON WM 12/1800, WM 36/500, and DM 145/700

WM chamber Insulation 1 3 Require test on RPSEA prototype

Creating a clean type environment

2 3 Technique exists for AC connectors; different criteria needed for DC

Housing/outer barrier - Electrical properties - Mechanical properties

1 4

3 4

Require test on RPSEA prototype Barrier technology implemented in all MECON WM products

4. Summary

In summary, a technical gaps analysis has been performed for the subsea DC connectors, and the

fundamental technical challenges for these connectors that cannot be addressed using existing

technologies include:

i) Establishing a reliable DC insulation system within the subsea-compatible mechanical

enclosure

ii) Maintaining reliable DC insulation even under the possible influence of seawater

contamination during WM process

iii) Achieving ultra-high electrical reliability, satisfying the need for deep sea operation

In order to address these fundamental challenges, a technical gap-closing strategy is proposed for the

RPSEA project, which includes developing and testing an electrical prototype mock-up unit at ±50kVDC

rated voltage, and investigating the scale-up relationship for higher voltage ratings by testing

components with simplified geometries and different sizes. The learnings from the proposed 50kV

prototype development include:

Validation of UDW-compatible DC insulation on real geometry Determination of the influence of seawater on DC connector electrical insulation


50

Development of size vs. voltage scale-up relationships (extracted from simplified model testing) Execution of a bench-top electrical qualification at 50kV level With regard to the applicability of the proposed approach to higher voltages, the proposed approach will provide the following information which is critical for the design of future connector products: Validated design concepts and materials selection Knowledge on the effect of seawater A scale-up relationship that can be used to make adjustments on design levels for higher voltage

ratings The issues not addressed in the approach include: Engineering challenges that may occur by increasing the dimension of insulation systems

(applies to all subsea connectors and not specific to DC) This approach does not include development of new insulating material, because the

development and qualification of such a material can take several years. Thus, the proposed approach focuses on innovative structure design and combination of existing materials to address the challenges for subsea DC connectors. However, this approach does include possible modification of existing materials (e.g., adding functional fillers or applying surface coating to an existing proven material).

References

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51

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[17] Y. Kamei, M. Baba and S. Fujita, "Space charge in polyimide film after water absorption," in The 6th International

Conference on Properties and Applications of Dielectric Materials, Xi'an, China, 2000.

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Houston, 2009.

[23] I. Østergaard, G. Sande, A. Nysveen and F. Greuter, "MECON – a novel high-voltage subsea power connector," ABB

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[24] S. Mashio, "Nano-Composte DC-XLPE cable for 250kV HVDC Link in Japan," in ICC Fall Meeting 2012, 2012.


52

[25] T. Worzyk, Submarine Power Cables, Springer, 2009.

[26] CIGRE, "Recommendations for Testing DC Extruded Cable Systems for Power Transmission at a Rated Voltage up to 500 kV

(This TB replaces TB 219)," CIGRE, 2012.

[27] C. W. B1.32, "CIGRE TB496: Recommendations for testing DC extruded cable systems for power transmission at a rated

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53

Appendix: Minutes of Meeting, Second Open Industrial Workshop

Minutes of Meeting

Document no. Page

53 of 61

Rev.: 1

Subject Meeting no.

Second Open Industrial Workshop - Technical Gap Analysis for Subsea DC

Connectors (RPSEA Project 12121-6302-01, GE Global Research)

1

Date Time Location

March 25, 2015 7:30-3:00 CDT Houston, TX; teleconference + webex

Minutes by Date for

sign.

Qin Chen 04/14/2015

GE Global Research


54

Participants (alphabetic order):

BP Michael Scroggins

Consultant (formerly GE Oil & Gas): Svend Rocke

Exxon Mobil: Kevin Corbett

Xiaolei Yin

GE Global Research (GE GR): Chris Calebrese

Jeff Sullivan

Fengfeng Tao

Liwei Hao

Qin Chen

Yanju Wang

GE Oil & Gas (GE O&G): Albert Ericsson

Gorm Sande

Jan Erik Elnan-Knutsen

Kristin Elgsaas

KPI/Chevron Norman Ritchie

NETL: Gary Covatch

Roy Long

RPSEA: James Pappas

Shell: David Liney

TOTAL: Khalid MATEEN

Absent


55

Item No. Subject Resp. Due

1 Agenda:

7:30 – 8:00 Welcome (Coffee and light breakfast)

8:00 – 9:00 Project status update

9:00 – 11:30 Technical gap analysis report out & discussions

11:30 – 12:30 Lunch

12:30 – 3:00 RPSEA project gap-closing strategy report out &

discussions

Information

2 Action items

2.1 Prepare gap analysis final report

- Include results obtained after draft report

- Clarify what HV means – when is 50kV, when 150kV

- Change onshore & subsea storage time to max (not minimum)

- Technical Requirements: clarify how the electrical ratings for DC

connectors were derived

GE GR 4/3/15

2.2 Test procedure review

- Schedule review meeting

- List design voltage vs. test voltage (e.g. FAT) vs qualification

voltage (type testing)

- Justify each test parameter

- Include withstand tests (preferably before/after aging test)

- Review subsea conditioning test method

- Use "degraded" oil for testing to understand the effect

GE GR 5/1/15


56

Item No. Subject Resp. Due

2.3 Adjustment of project schedule

- Move some of the “HV materials test” to before 2nd

prototype

by starting early the HV material testing and delaying the 2nd

prototype testing, so that the outcome can be used in 2nd

prototype

- Study stress control mechanisms and evaluate the need for

special stress grading materials for higher voltage ratings up to

150 kV

- Shorten prototype-level deep sea condition test in order to

accommodate the delayed prototype testing.

- List what tests are done on what object (materials, simplified

geometry, or prototype)

- Review by WPG

- Determine whether SOW change is needed; review & approval

by Gary and James

GE GR 5/1/15


57

3 Questions and answers

3.1 Regarding schedule:

Q: Why go/no-go #2 is so late? (Xiaolei)

A: This go/no-go point is right after stages 2-1 (prototyping) and 2-2 (test

without seawater). In the original proposal the two stages run in series with a

decision point in between; however when the project was shortened from 36

to 27 months due to programmatic need, the two stages become largely in

parallel so it’s difficult to insert go/no-go in the middle. (Qin)

Q: Little time between 2 prototypes to make changes. How can we start the

second prototype before the testing on the first is done? (Norman)

A: (i) when considering schedule adjustment we will consider extending the

time between the two prototypes; (ii) prototype 1 testing won’t include full-

length aging, but rather shorter tests to provide critical feedback – e.g., AC

withstand, partial discharge, DC withstand, load cycle, impulse, etc. (iii) We

won’t wait for the testing to finish before start changing design. The design

optimization is to be a continuous effort, feedback from each step in the test

will be immediately considered in design. Design will also be improved based

on materials-level tests. ( (Qin)

Information

3.2 Regarding electrical test

Q: where did the 2.5xU0 overvoltage come from

A: from system simulation (not from IEC standard) (Qin)

Q: Have we identified all the existing standards? (Xiaolei)

A: We found CIGRE TB496 and Electra 189 (Qin/Liwei)

Information


58

3.3 Subsea condition test

Q: Do we need to test the pressure effect at the rated pressure? (Xiaolei)

A: Yes, need to do this at least on materials level. Results can be used to

design prototype test method (Qin)

Q: Depending on whether pressure is important, may or may not need full

pressure for prototype subsea conditioning (David)

A: agree, pressure effect can be evaluated on materials level to guide

prototype test protocol (Qin)

Comment - Need to consider how to protect un-exposed portions of epoxy

during sea water exposure otherwise the fully exposed sea water material

test may be too arduous (Norman)

Comment – Ensure prototype is fully protected in the same manner as similar

production equipment for all transportation activities. Svend stated that this

is/will be in the execution/logistics procedure(s) (Norman)

Q: Does assemble process alter surface conditions so that the test is no longer

representative? (Xiaolei)

A: Details of seawater conditioning test to be finalized, but in general, to

minimize altering – (i) assembled, closed, and sealed right after conditioning,

then the WM chamber is an enclosed chamber with oil - similar to the actual

subsea connector after WM & flushing is finished; (ii) no vacuum or

heating/drying involved between seawater conditioning and finishing of

assembly

Information


59

3.4 Regarding seawater effects

Q: Can we apply existing technologies to limit contamination, e.g.,

hydrophobic coating (Khalid)

A: It’s possible, but need consider: (i) how much improvement can we gain;

(ii) how does the coating change the electrical properties; (iii) long term

reliability, ruggedness, compatibility; (iv) manufacturing feasibility (Qin)

Q: How long can a connector be exposed to seawater (Xiaolei)

A: It’s a 2-sided question, should set a value for DC connectors based on

tolerance of contamination (Svend); The connector can be recapped and

flushed in storage while subsea (Gorm); also need to note that biology is a

consideration when how long a connector can be open to sea water (Svend)

Q: How can surface contamination effects be mitigated prior to the whole-

connector subsea doing bench-top type experiments? (Khalid)

A: Fundamental understanding is gained by testing materials; However, to

prove understanding is applicable for connectors, prototype-level validation is

also critically needed (Qin)

Q: Is there a plan to test epoxy coating(s) preventing sea water

ingress/contamination? (Norman)

A: Possible for materials; could fold into prototype 2 also, but need to worry

introducing new failure mode (Jeff) Oceanit is a vendor having a coating with

excellent an-hygroscopic properties (Roy)

Q: Absorption or adsorption? (Khalid)

A: (i) contaminants is not likely only on the surface, due to weight percentage

and bulk conductivity results; (ii) but surface may control the rate of

absorption – need verify (Qin)

Q: Have we considered ceramics (Norman)

A: Ceramics has been considered and found unsuitable for the voltage rating.

Ceramic materials are required for electrical insulators interfacing processing

fluids/gases and GE has a project experience with ceramic penetrator design

at 12 kV insulation class. One of our key learnings from working with

ceramics is the limitations on physical dimensions that must be applied in the

design, i.e. large ceramic insulators are increasingly difficult to manufacture

due to the difference in thermal expansion between the conductor material

and housing material it’s bonded (usually brazed) to. (Jan-Erik)

Information


60

3.5 Regarding stress control

Q: Can oil be used as "stress absorber" to turn stress management during a

transient event into an engineering problem instead of a materials problem?

(Khalid)

A: It’s true that oil can “absorb” excessive stress from solid during impulse

events. However there are other locations in the connector solely relying on

solid insulation (e.g., termination, some part of WM chamber) and situation

there is very different.

Q: In WM chamber, need to worry stress around connection area (David)

A: Agree, any structure under electrical stress needs to be worried. “Non-

electrical” structures are those not under high electrical stresses – e.g., outer

metal shell, high current contacts, etc.

Q. Need for Stress Grading Material for 150kV: Question was asked whther

we could have a design without the use of new stress grading material for

150kV.

A. The response was that without the use of adequate stress grading material

the size of connector (diameter) will become too big, almost three times that

required for 50kV. There have been other stress grading material already

identified in GE earlier work which could be studied for 150kV use.

Information


61

3.6 Electrical rating

Q: preliminary engineering design – 50kV and 100kV are for different power

levels, not apple-to-apple comparison (Norman)

A: The purpose is to look at the size of prototype at different voltages

following the same design rule (i.e., same max electrical stress), thus

estimating the engineering challenge for prototyping. It’s not for comparing

different voltage levels for the same power need. (Qin)

Q: Are we making a prototype satisfying no/little business need, but for

learning purpose (Norman)

A: Business need is at high power long distance (>40MW, as high as 100MW

i.e. need 150kV), but not a waste if we can see significant risk reduction

towards 150kV (Khalid);

A: Agree on 100MW need; but for higher power compressors (today 10MW,

future 20MW+), 20-40MW connectors could be used for very long distance

compressors (Kevin)

A: Do not agree with this conclusion (Khalid)

A: Besides very high power needs, there could be also applications with very

long distance but lower power (Kristin)

A: due to variation of opinions, I would suggest a brief market

analysis/users’poll is conducted to obtain the value proposition for these

connectors – there seems to be differing opinions in the step-out length vs

voltage vs power ratings of subsea electrical equipment/electrical connectors

(Norman)

A: Although with different opinions on the commercial value of a 50kV DC

connector, it can at least serve the purpose of technology demonstration and

validation in pilot systems or in the field before investing on very large

offshore O&G fields with high power DC system. The development of

extruded HVDC cables with DC XLPE insulation followed a similar path. For

instance, in the case of the ABB HVDC Light cable, the development first

concentrated on a 10kV, 3MW system (Hellsjön project, 1994-1997), and then

the voltage/power rapidly reached 80kV, 50MW (Gotland project,

commissioned in 1999), and then 150kV, 220MW (Murraylink project,

commissioned in 2002). (Qin)

Information

subsea hvdc connectors technical gaps analysis final report · for dry-mate (dm) connectors....

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