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Direct Electrical Heating of Subsea Pipelines—Technology Development and Operating Experience Article  in  IEEE Transactions on Industry Applications · February 2007 DOI: 10.1109/TIA.2006.886425

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Direct Electrical Heating of Subsea Pipelines—Technology Development and Operating Experience Arne Nysveen, Member, IEEE, Harald Kulbotten, Jens Kristian Lervik, Atle Harald Børnes, Martin Høyer-Hansen, and Jarle J. Bremnes

Abstract—The formation of hydrates in the subsea production of oil and gas is a well-known problem. As the unprocessed well stream cools down, hydrates start to form around 25 ◦ C, depending on the water cut and pressure in the pipeline. Several solutions are available to solve this problem. Generally, chemicals (i.e., methanol) have been used. Methanol reduces the critical temperature where hydrates are formed. Alternatively, hydrates can be prevented by using thermal insulation in combination with direct electrical heating (DEH). Thus, the well stream is kept above the critical temperature for hydrate formation. DEH heats the pipeline by forcing a large electric current to flow through the pipeline steel. The system model for design and sizing of the system is presented. DEH uses a single-phase system where the heated pipeline is electrically connected to the surrounding sea water. Thus, the system current is divided between sea water and pipeline, requiring additional sacrificial anodes on the pipeline. The anode system for a pipeline with DEH is discussed. There are currently more than 100 km of DEH pipelines on the Norwegian Continental Shelf. The operating experience from these installations is discussed. This paper presents the research and development for application of the system for pipelines with lengths up to 50 km. Index Terms—Electrical heating, hydrates, sacrificial anodes.

I. I NTRODUCTION A. Hydrate Prevention in Subsea Pipelines

T

HE well stream in offshore oil production normally contains considerable amounts of formation water. The volumetric content of water (water cut) may vary from 10% to as high as 80% in the tail production phase. In a subsea Paper PID-06-15, presented at the 2005 IEEE Petroleum and Chemical Industry Technical Conference, Denver, CO, September 12–14, and approved for publication in the IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS by the Petroleum and Chemical Industry Committee of the IEEE Industry Applications Society. Manuscript submitted for review September 15, 2005 and released for publication September 15, 2006. This work was supported by Statoil ASA. A. Nysveen and M. Høyer-Hansen are with the Norwegian University of Science and Technology, 7491 Trondheim, Norway (e-mail: Arne.Nysveen@ elkraft.ntnu.no; [email protected]). H. Kulbotten and J. K. Lervik are with SINTEF Energy Research, 7465 Trondheim, Norway (e-mail: [email protected]; Jens.K.Lervik@ sintef.no). A. H. Børnes is with Statoil ASA, 4035 Stavanger, Norway (e-mail: atlb@ statoil.com). J. J. Bremnes is with Nexans Norway AS, 1751 Halden, Norway (e-mail: [email protected]). Color versions of one or more of the figures in this paper are available online at http://ieeexplore.ieee.org. Digital Object Identifier 10.1109/TIA.2006.887425

production system, several wells are tied into a manifold. From the manifold, the main pipeline is tied to a platform or to shore. As the hot well stream cools down, hydrates may be formed inside the pipeline, causing a reduction in the flow and ultimately completely blocking the pipeline. Depending on water cut, salt content, and pipeline pressure, hydrates can be formed at temperatures as high as 25 ◦ C. Furthermore, wax starts to deposit inside the pipeline at even higher temperatures, i.e., 35 ◦ C–40 ◦ C. It is therefore essential to keep the well stream above a critical temperature in order to maintain a steady flow. Process engineering has several solutions available to prevent the formation of hydrates during production. The choice depends on the length of the pipeline, the water cut, and the lower critical temperature for hydrate formation, as well as regulatory requirements. By injecting chemicals in the well stream at the well head or manifold, hydrates are formed at much lower temperatures. Normally, methanol is used. There are drawbacks with methanol injection. Methanol needs to be separated from the well stream at the topside process facility, and methanol occupies space and reduces the capacity of the pipeline. Moreover, it must be treated in the process facility before it is reinjected into well stream. Additionally, environmental regulations limit the methanol contents in the produced water that is dumped into the sea. Applying thermal insulation on the pipeline reduces the wellstream temperature drop between the well head/manifold and the process facility. For shorter distances and/or high reservoir temperatures, this may be a sufficient measure. However, during shut down and production at lower flow rates (tale production), it is difficult to maintain the well-stream temperature above the critical limit. By heating the pipeline electrically, the need for chemical injection is reduced considerably. Electrical heating has shown to be very suitable for long pipelines since heat can be generated evenly along the whole length. Nonelectrical options, such as hot water supply using pipes embedded in the thermal insulation, are not dealt with here. B. Electrical Heating of Pipelines The pipeline can be heated electrically by several methods. Two of these are illustrated in Fig. 1. The embedded cables constitute a three-phase system. At the manifold end of

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Fig. 2. DEH with strap-on piggyback cable and current-carrying pipeline. Fig. 1. Heating methods of pipelines. (a) Using cables as resistive heat elements. (b) Using cables for heating the pipeline wall by induction. Currents are induced in the pipeline wall.

the pipeline, the cables are wye connected (short circuited). The heat is generated by ohmic loss in the cable conductors [Fig. 1(a)] or in the pipeline wall by induced currents [Fig. 1(b)]. When using power cables as heat elements [Fig. 1(a)], the distance between the pipeline wall and the cables must be small. Otherwise, a large portion of the heat is dissipated into the sea. Furthermore, the voltage needs to be low in order to allow for thin cable insulation. For this method, the electric and magnetic properties of the pipeline wall material only have moderate influence on the dissipated heat in the cables. For inductive heating, the loss dissipation in the pipeline wall depends on the electric and magnetic properties in the pipeline material. Normally, a magnetic steel quality is required. The heat generation can be optimized by tuning the power supply frequency. A problem with both of the above methods is how to embed the cable inside the thermal insulation. During offshore pipe laying, the separate pipe joints (pipe lengths of typically 12, 24, or 48 m) are welded into a pipeline on the installation vessel in a continuous process (S-lay and J-lay techniques). The cable length is much longer than the length of the pipe joints. Therefore, the cable is laid down in slots in the thermal insulation. The slots are made either when applying thermal insulation or subsequently by cutting [1]. A large advantage with the methods presented above is the galvanic insulation between the electric power circuit and the pipeline. The risk of stray currents and corrosion is absent as long as the cable insulation remains undamaged. However, the alternative method where current is flowing in the pipeline wall has shown to be the most economical and reliable ac solution. The direct electrical heating (DEH) system consists of a single-phase ac supply where the current flowing in the pipeline wall returns in a cable in parallel with and in close proximity (“piggyback”) to the heated pipeline (Fig. 2). Here, the cable can be strapped onto the pipeline during the installation process. It is also possible to install the piggyback cable separately on the sea bed, but this results in a larger distance between the cable and the pipeline and hence in a larger power requirement. In this paper, the DEH of single pipelines is presented. This paper starts with a description of the concept, rating of the

system, anode design, and corrosion protection. Further, new developments for long pipelines (> 40 km) are presented. Long pipelines lead to excessive cable screen-to-ground voltages. Different methods to handle this effect are discussed. Currently, a new cable with semi-conductive sheath is under development. The test program and some results are presented. At the end, operational experiences from several field developments on the Norwegian Continental Shelf are given. II. DEH A. System Description In DEH, the pipe to be heated is an active conductor in a single-phase electric circuit, with a single core power cable as the forward conductor (see Fig. 3). Power is typically supplied via a rise cable from the platform main power. One of the two riser cable conductors is connected to the near end of the pipe. The other is connected to the piggyback cable, which is again connected to the far end of the pipe. The pipeline employs cathodic protection with sacrificial anodes. Normally, aluminum anodes are used. The heating system is thus galvanically connected to the surrounding sea water through sacrificial anodes, and the sea water acts as an electric conductor in parallel with the pipe. In other words, the current flowing in the piggyback cable will be divided between pipe and sea water. Two main consequences are listed as follows: 1) reduced pipe heating for a given cable current (unwanted); 2) no significant voltage difference may occur between the near and far end of the pipe (wanted). At the far-end cable connection point, the cable current enters the steel pipe, while part of the current leaves the pipe and is transferred to the sea through the anodes. The electrical current in the sea water enters the pipe again at the near-end connection point. Typically, 40% of the total current flows in the sea water. In order to control the added ac corrosion of sacrificial anodes at the cable connection points, additional anodes of the same type are used in these current transfer zones of typically 50 m. Fig. 4 shows the circuit diagram for the DEH system. The current in the piggyback cable (Icable ) returns back in the pipeline (Ipipe ), the cable screen (Iscreen ), and the sea water (Isea ). In designing and dimensioning a system for the given pipeline, the portion of the total current returning in the pipeline, the ac resistance of the pipeline, and the total system

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Fig. 3. Outline drawing of the DEH system. The efficiency of the system has a maximum value in a piggybacked installation.

flowing in the cross section of the pipeline, screen, and sea water is set to be −Icable . Hence, one ensures that Icable = Ipipe + Iscreen + Isea .

The program computes the electromagnetic field and temperature distribution dissipated heat, the induced voltage in each conductor, and the current distribution between the pipeline, cable screen, and sea water. It is important to model a sufficiently large part of the surrounding sea water in order to ensure that the potential drop in the sea water along the pipeline comes close to zero. The system impedance is given by

Fig. 4. Circuit connection diagram for the direct heating system.

impedance are the governing parameters. In principle, these values can be calculated in a circuit approach when all conductor resistances and self and mutual inductances are known, i.e.,    Ucable Icable  Upipe   Ipipe   = [Z] ·  .  Uscreen Iscreen Usea Isea

(2)



(1)

Neglecting the end effects at the current transfer zones, the sea water is at zero (ground) potential along the whole pipeline. When neglecting capacitive effects, the cable screen and the pipeline will also be at ground potential along the whole length. Hence, Ucable equals the applied voltage Us . The equation system can now be solved. Calculation of all the parameters (Z-matrix) can only be made by numerical analysis due to the uneven current distribution in the cross section of the piggyback cable, cable sheath, and pipeline. Since we are primarily not interested in all the impedances in (1), a more direct method using two-dimensional (2-D) finite-element method (FEM) analysis (Flux2D) [2] is adopted. A 2-D cross section (shown in Fig. 2) is used for the FEM analysis. In the FEM model, the current in the cross section of the cable is set to a specified value Icable . The sum of currents

Zsys =

Ucable Icable

(3)

where Ucable is computed in the FEM analysis, and Icable is equal to the specified input value. When magnetic steel is used in the pipeline (carbon steel), the magnetic permeability has a profound influence on the system. A high permeability enhances the skin effect, thereby increasing the power dissipation in the pipeline for a given pipeline current (Ipipe ). However, the impedance in the pipeline also increases with the increase in magnetic permeability, causing a counteracting reduction in the pipeline current. B. Determining the Rating of the DEH System The following information is required when designing DEH: • cross-sectional layout drawing with dimensions of the pipeline, including piggyback cable cross section and cable mechanical protection; • length of pipeline; • electrical conductivity and magnetic permeability of the pipeline; • thermal conductivity with corresponding U -value and heat capacity for the pipe insulation, cable protection, and surrounding seabed (including depth of gravel, rock dumping, etc.);

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• thermal properties of the pipe fluids in different operating modes; • temperature and electrical conductivity of sea water; • temperature requirements of the pipe fluids to prevent hydration; • required maximum time for heating from a cold state. The output data are as follows: • required in-feed voltage and current, and thus required cable dimensions; • active and reactive power requirements; • system impedance; • current distribution between pipeline, sea water, and cable screen; • cable temperature at different modes of operation. Operational requirements and pipeline design data must be provided by the project. Cable data and some pipe data are provided by the manufacturers. However, the electrical conductivity and magnetic permeability of the steel pipe will vary depending on material, manufacturer, and even between manufactured batches. When statistically reliable data are unavailable, measurements of the magnetic permeability must be performed on the actual pipe batches. Otherwise, sufficient contingency must be incorporated in the system rating to ensure that pipe lengths with low relative permeability give the required heat generation for a given current Icable . The electrical heating concept is developed for thermally insulated pipelines. Typical U -values are 3–7 W/m2 K for pipes with thermal insulation. Lower U -values may apply for buried pipelines. The cable rating and pipe current required are strongly dependent on the thermal characteristics of the pipe content in the different phases, i.e., the mixture of gas, oil, and water. When calculating the required heat development, the “worstcase situation” from a thermal point of view is the case of minimum coverage. In most cases, this is when the insulated pipe is located on the seabed (surrounded by sea water), as shown for the configuration in Fig. 5(a). The maximum power (current) needed for avoiding wax and hydrate formation is then determined by the lowest observed temperature of the sea water. The cable conductor cross section is normally governed by the thermal limits of the cable insulation. Maximum temperature occurs where the pipeline is buried or rock dumped with the maximum depth of backfill. Fig. 5(b) illustrates the “worst case” with respect to the thermal condition for the cable, which is limited to 90 ◦ C for cross-linked polyethylene (XLPE) cable insulation. The thermal rating of the cable must also be considered if for any reason heating is required while the pipe is in production mode.

C. DEH Topside Equipment DEH will typically be supplied with power from the platform receiving the oil and gas in the pipeline to be heated. The DEH system is a single-phase inductive load with a poor power factor. Connecting this load to the topside power supply requires certain measures.

Fig. 5. (a) Pipeline and DEH cable surrounded by sea water. This case determines the heat requirement. (b) Maximum coverage of the pipeline. This represents the “worst case” with respect to the thermal condition for the cable.

First, the voltage on the grid has to be transformed to a level giving the specified current in the DEH system. The required current may change during the operational phase, and final data for the pipeline system may not be frozen at the time the DEH transformer is purchased. The output voltage and currents of the transformer, therefore, have to include tolerances, and this could be achieved by designing the transformer with many tappings. The required number of tappings depends on the specified voltage and current tolerances as well as the acceptable change in current from one step to the next. For all systems delivered up to now, offload tap changers have been specified. The reason for this is that few alterations in the transformer tappings are expected after the commissioning phase of the system. Second, as the power factor of DEH is in the order of 0.3 in a piggyback configuration, phase compensation of the load is essential in order to reduce the loading on power supply equipment. Further, connecting a single-phase load in the megawatt range to the three-phase mains on a platform should be avoided. A load-balancing circuit of passive components has been designed as a mitigation measure. Fig. 6 shows a DEH circuit diagram with topside power supply, DEH transformer, DEH load-balancing circuit, and subsea DEH. The inductive load is compensated by shunt capacitors C2 . For most purposes, compensation to a power factor better than 0.9 is sufficient. Through this, the net load current Io is reduced to one-third of the uncompensated load current Icable .

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Fig. 6. DEH system circuit diagram with topside power supply, DEH transformer, DEH load-balancing equipment, and DEH load.

Fig. 7. Phasor diagram for a perfectly balanced load (assuming fully compensated load).

Assuming a fully compensated load current (I0 purely resistive), the single-phase DEH load can be perfectly balanced between the three phases of the mains by tuning C1 and L1 so that the following condition is met: √ IL1 = IC1 = I0 / 3 . (4) Fig. 7 shows the phasor diagram for a perfectly balanced circuit where IA = I0 + IC1 IB = IL1 − IC1 IC = −I0 − IL1 .

(5)

The purpose of RA , RB , and RC is to limit inrush currents when the DEH system is energized. Instead of using a load-balancing circuit, a static frequency converter can be used. The cost of a converter is significantly higher than a circuit based on passive components, and this has to be evaluated against the flexibility the converter offers in terms of current regulation. A system based on passive components requires tapping of the DEH transformer in order

Fig. 8. Conductor-to-ground voltage in the cable decreasing linearly toward the connection point to the pipeline.

to adjust the supply current. If the transformer is equipped with off load tap changer, this necessitates de-energizing the circuit in order to change the output voltage of the transformer. D. Fault Protection of DEH The overall safety requirement for the DEH system is that a cable failure is detected and located without causing damage to the pipeline. The requirements for fault protection differ from a conventional cable installation as the DEH system, by its inherent design, is operated with two “ground faults” present. Due to the grounding of the cable system, the conductor-to-ground (i.e., sea water) voltage is linearly decreasing from full voltage at the topside terminal to zero voltage at the far-end cable connection point to the pipeline (see Fig. 8). Conventional overcurrent and impedance protection will provide adequate protection against faults for the major part of the pipeline. For the far end of the pipeline, supplementary protection is under development.

NYSVEEN et al.: DEH OF SUBSEA PIPELINES—TECHNOLOGY DEVELOPMENT AND OPERATING EXPERIENCE

Fig. 9. Example of temperature variation in groups of pipes with high and low permeability.

III. E LECTRICAL P ROPERTIES OF P IPELINE M ATERIALS The electrical and magnetic properties of steel pipe are essential for determining heat generation and efficiency of DEH. The ac resistance of the pipeline is given by the resistivity and depth of magnetic field penetration. Experience has shown that the relative permeability is a critical factor for both Carbon and 13Cr steel pipes. These data are normally not available from pipe manufacturers. Measurements have shown that X60, X65, 13Cr, and Duplex Steel do not possess uniquely defined electromagnetic characteristics. Measurements performed on large numbers of pipe joints show a significant variation of magnetic permeability. This shows that the magnetic material characteristics are not properly covered by production quality programs. A large random variation of permeability between individual pipe joints in a pipeline causes variation in pipe temperature due to variation in ac resistance (skin effect). This effect is illustrated in Fig. 9, with one pipe joint having a lower permeability. The pipe joint with low permeability does not reach the target temperature. Another important effect of variation in the magnetic permeability is that the impedance of the pipe varies along the pipeline. This results in current transfer between sea water and pipe, where anodes or cracks in the thermal insulation are present. The problem can be solved by dividing the pipeline into sections, each with a limited variation of the effective relative permeability. In practice, the individual pipes are sorted into groups based on measurements of the effective relative permeability. At the joint between two sections of different magnetic permeability, there is a current transfer between the pipe and the sea. Additional anodes are installed at these locations to facilitate current transfer. IV. R ISK FOR AC C ORROSION W ITH DEH A pipeline system is normally equipped with evenly distributed anodes for cathodic protection. Aluminum anodes are used. For DEH pipelines, additional anodes (i.e., electrodes) are installed at each end of the pipeline. In the current transfer zones, the pipes are equipped with a sufficient number of anodes to keep the transfer current density below values that can lead to ac corrosion. In our design, a current density of 40 A/m2 has been used. Cracks in the thermal insulation can lead to leakage currents due to variation in the impedance along the pipelines, as described in Section III. Studies on ac corrosion in carbon steel have shown that there is no significant corrosion for current densities below 240 A/m2 provided that the steel is protected by anodes.

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Cracks in the thermal insulation in the current transfer zone may cause high leakage current. Analyses have shown that leakage current depends on the distance from an anode. If the crack occurs close to an anode, the leakage current becomes smaller. It is therefore important that the distance between the anodes in the current transfer zones is small. V. DEH C ABLE D EVELOPMENT A. Operational Requirements Medium-voltage XLPE cables normally have an outer PE sheath for mechanical protection but no outer metallic sheath (wet design). Hence, there will be diffusion of water into the insulation. Nevertheless, few problems with water treeing have been observed [3]. It is believed that this is mainly due to the low operating temperatures and moderate field stress in the XLPE insulation. The DEH piggyback cable will experience new requirements. • Higher operating temperature—The DEH piggyback cable is installed adjacent to the pipeline and could be partly or completely buried. Heat from the pipeline and losses in the cable when DEH is energized may cause high temperatures on the cable. This is valid for both DEH systems in continuous operation (long pipelines with critical temperature drop along the line) and DEH systems used only during shut downs. The latter buried parts of the pipeline may still be hot while other parts directly exposed to sea water have cooled down, meaning that DEH must be energized. • Intermittent operation—DEH is energized during shutdown and startup. The rapid cooling of the power cables might cause condensation of water inside the XLPE insulation, which might again affect water tree growth. • High currents in cable screen—The purpose of the screen is to provide effective drainage of capacitive charging currents to ground. The grounding of the outer semiconducting layer will ensure that the voltage across the cable-protecting sheath is low. Since this necessitates grounding at both ends of the cable, the screen becomes a shunt for the current flowing in the sea. Thus, the resistance of the screen must be high. For long cables at high voltage, the screen voltage assumes high values due large charging currents. Thus, a traditional solution with metal screen cannot be used. • Elongation/strain in cable—The cable is mechanically anchored to the pipeline in the cable to pipeline terminations. During operation, the pipeline experiences thermal expansion and contraction due to startup and shutdown of the process (i.e., cool down when supply of warm liquid is stopped). Consequently, the tensile capacity of the cable is an important design parameter. • Impact loads—The DEH piggyback cable could be installed in areas with fishing activities (interaction with trawl gear) and risk for dropped objects. A conventional sea cable design with heavy outer armoring is not compatible with DEH as the induced armor currents will significantly reduce the efficiency of the system and cause high

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Fig. 11. DEH cable conductor voltage and screen-to-ground voltage are plotted versus distance. 1 kA is applied to a 50-km 10-in carbon steel pipe and calculated according to [5].

Fig. 10. (a) Cross section of a cable with an insulating outer sheath and a metallic ground screen. (b) Per-length circuit equivalent for the DEH system. Zc : cable impedance; Zs : sheath impedance; Zg : ground impedance; Cd : cable insulation capacitance; Cs : sheath capacitance.

cable temperatures. Hence, the cable has to be protected by other means. A method for mechanical protection of the cable is described in [4].

B. Calculation of Screen Voltage The piggyback cable design for the first DEH projects is shown in Fig. 10(a). The cable has an insulating outer sheath and a metallic screen of stainless steel, grounded at both ends. In order to obtain high efficiency, the high resistivity in the metallic screen minimizes the induced screen currents. A per-length circuit equivalent for the DEH system is shown in Fig. 10(b). The impedances are calculated by using a numerical software program based on FEM. Calculation of voltages and currents along the cable is performed by subdividing the cable into short sections. Each section was modeled by the exact PI equivalent (long wave) [5]. By this method, the circuit with terminal conditions was solved using the nodal admittance method. The calculating procedure for each PI equivalent presented in Fig. 10 is described in [6]. Calculations for a DEH cable of 1500-A 12-kV 1000-mm2 conductor cross-sectional area show that the screen-to-ground voltage exceeds 1 kV for a length of 15 km. 1500 A is required to heat an 18-in carbon steel pipe with pipe insulation coefficient U = 4 W/m2 K. The outer sheath of the piggyback cable cannot withstand high voltage, and avoiding a high screen voltage to ground in long piggyback cables must therefore be resolved by other methods. Fig. 11 shows the conductor voltage and screen-to-ground voltage versus distance for a 50-km piggyback cable. The con-

Fig. 12. Maximum screen-to-ground voltage for different lengths of DEH cable, as calculated in [5] and [6]. The calculations were performed with a 50-Hz cable current of 1.5 kA and an 18-in carbon steel pipe.

ductor voltage decreases linearly from the in-feed end toward the grounded end. The screen voltage increases rapidly from the grounded topside and reaches its maximum value at about 15 km. The maximum screen-to-ground voltage is ∼9 kV, which is far above acceptable levels. Fig. 12 shows the maximum screen-to-ground voltage for cables of lengths up to 50 km, carrying a current of 1.5 kA at 50 Hz for 18-in carbon steel pipeline. The screen voltage is low for short cable lengths, while it increases rapidly above 15 km. C. Managing Screen Voltage for Long Pipelines In a traditional cable design using a relatively poorly conductive metal screen, the voltage between the screen and the ground (sea water) becomes too high for long cables, as shown in Fig. 12.

NYSVEEN et al.: DEH OF SUBSEA PIPELINES—TECHNOLOGY DEVELOPMENT AND OPERATING EXPERIENCE

Fig. 13. (a) Both ends connection of the piggyback cable. (b) DEH with two half-way-connected sections. (c) Intermediate grounding of the screen.

The screen voltage could be reduced by using a copper screen (lower resistivity), but this would reduce the DEH efficiency since a smaller part of the total current will flow in the pipeline. The high screen voltage can be reduced by introducing sectioned DEH. The simplest method consists of connecting the cable close to the midpoint of the pipeline, as shown in Fig. 13(a). The length of each section is reduced to one-half. From Fig. 12, it can be observed that splitting a 30-km pipeline into two 15-km sections reduces the screen-to-ground voltage from 4.3 to 1.2 kV. For longer pipelines, two half-way-connected sections can be used, as shown in Fig. 13(b). The advantage of this solution is that a “traditional” cable design with high resistance metal screen is applicable. The drawback of this solution is cost for the extra length of feeder cable to the junction boxes. Further cost increase is caused by the following: • additional cable terminations to the pipeline and additional sacrificial anodes; • increased active and reactive power loss due to the extra length of feeder cable; this requires larger power supply equipment. The large cost increase of a system divided into sections compared to a simple one has trigged a search for alternatives. The cable screen of the piggyback cable can be grounded at intermediate points along the heated section [see Fig. 13(c)]. This solution has lower costs since it does not require additional feeder cables. The screen-to-ground voltage profiles of a 50-km-long cable grounded every 5, 7.5, and 10 km, respectively, is shown in Fig. 14. The alternative solution for the Tyrihans DEH pipeline (43 km, 18 in) is to use a semi-conductive outer cable sheath (Fig. 15) and thereby draining the charging currents continuously to the sea. This is the most feasible solution for long pipelines. A circuit equivalent is shown in Fig. 16(a). Zc denotes the cable impedance, Zs the sheath impedance, and Zg the ground (sea water) impedance. Cd is the cable insulation capacitance between the conductor and the cable screen, while Cs is the

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Fig. 14. Screen voltage distribution for a 50-km 18-in pipeline intermediately grounded every 5, 7.5, or 10 km.

Fig. 15. Tyrihans DEH cable with (1) semi-conductive outer sheath, (2) outer insulation screen, (3) XLPE insulation, (4) inner insulation screen, and (5) conductor with semi-conductive strand sealing.

sheath capacitance between the screen and the ground. Rs denotes the resistance in the semi-conductor sheath. For a sheath resistivity lower than 100 Ωm, the current through the sheath capacitance (Cs ) can be neglected compared with the current in Rs . For calculations of topside conductor voltages and currents, the per-length circuit equivalent can be simplified to the circuit in Fig. 16(b). Here, Z is the system impedance, calculated by FEM as in Section II-A. I1 and I2 are the currents at the host and far end, respectively, U1 is voltage drop at the host, k is the propagation constant, and l is the length of the pipeline. From Fig. 16(b), the following equations are derived: I1 /I2 = cosh(kl) U1 = I2 · Z · sinh(kl)  k = jωCd Z .

(6) (7) (8)

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Fig. 16. (a) Per-length circuit equivalent for the DEH system with semiconducting sheath. (b) Simplified per-length circuit equivalent for the DEH system.

D. Testing of Cable With Semi-Conducting Outer Sheath Using a cable with semi-conductive outer sheath represents two sets of challenges: 1) finding a suitable sheath material with acceptable electrical, thermal, and mechanical properties; 2) impact on the XLPE insulation system. After the initial screening of several materials, three candidates were nominated for further testing. Two candidates were based on polyethylene and one on polypropylene. Samples from the candidate materials were aged in a pressurized vessel with sea water. The electrical and mechanical parameters were measured on both unaged and aged samples. Based on the test result [7], the sheath material for the Tyrihans prototype cable fabrication was chosen. High cable operating temperatures—up to 90 ◦ C—and intermittent cycling (large temperature variations) combined with high hydrostatic pressure represent new challenges. The main concerns are insulation water trees and electrical/mechanical robustness. A long-term aging program has been initiated for the Tyrihans prototype cable, scheduled for completion in 2006. Lengths of the 52-kV cable are placed inside a pressure chamber filled with sea water. The chamber is pressurized to 30 bar. The temperature of the water is varied between 65 ◦ C and 90 ◦ C with a cycle time of 56 h representing one shut-down/start-up cycle. The test arrangement is shown in Fig. 17. Cable lengths will be removed and examined for water tree growth at a predefined interval, and samples will be subject to PD measurements and ac breakdown tests. VI. O PERATIONAL E XPERIENCE AND N EW D EVELOPMENTS A. DEH Systems Installed A general DEH feasibility program was run in 1996–1997. From this, it was decided that DEH should be the hydrate prevention method for six of the pipelines in the project Åsgard field development. Several projects have later been added to the DEH list. A brief description of these systems is presented in Table I. All DEH systems in Table I are located on the Norwegian Continental Shelf and operated by Statoil. The DEH systems are generally designed to meet the following design criteria:

Fig. 17.

Laboratory aging test of Tyrihans prototype cable. TABLE I SUMMARY OF DEH SYSTEMS INSTALLED BY STATOIL

• maintain the fluid temperature above hydrate formation temperature in the heated part of the pipeline during shutdowns; • be able to raise the temperature of the fluid from ambient to above hydrate formation temperature within a specified time period. The first item refers to a normal shut-down situation where DEH is turned ON after a few hours. No immediate energizing of DEH is required since the pipelines are designed with a low U -value in order to allow for several hours of “notouch.” The hydrate formation temperature is dependent on fluid composition and shut-in pressure and varies from field to field, but mostly design temperatures at around 25 ◦ C are specified. The second item refers to an abnormal situation where a full cool down of the fluid has taken place. If DEH is unavailable for any reason subsequent to a production shutdown (e.g., power supply “black-out” on the platform), this situation may occur.

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B. Operational Experience

Fig. 18. Piggyback cable ready for welding to the cable termination plate.

Raising the temperature from ambient (typically 4 ◦ C) to above hydrate formation temperature requires higher current than the case of maintaining the temperature above hydrate formation temperature. The current demand will increase with shorter “heat-up” times. The specified “heat-up” times for the DEH systems in Table I are typically 48 h. Huldra DEH is, in addition, designed to keep the arrival temperature above hydrate formation and wax precipitation temperatures during low production rates. During tail production, the temperature drops in the production pipeline such that the arrival temperature of the fluid is below a critical value without heating. All pipelines, except Huldra, are partly trenched, partly rockdumped, and partly exposed to sea water. The trenching and rockdumping are performed in order to reduce pipeline free spans on the uneven seabed. The exposed area determines the current demand, while the trenched area governs the cable sizing. The Huldra pipeline is trenched to 0.7 m and covered by back fill and/or gravel dump. The coverage ensures thermal insulation, protection against external loads such as trawling, and provides resistance against upheaval buckling. Since the pipelines will experience thermal expansions during operation, the piggyback cable may be subject to tensional forces as well as abrasion against the seabed and/or rock cover. Furthermore, the pipelines are installed in areas with fishing activity and possible interaction with trawl boards. In order to meet these mechanical load conditions, the piggyback cables for Åsgard and Huldra were designed with a polymer outer coating having resistance against abrasion and impact. For Kristin and Urd, a continuous mechanical protection profile was developed and installed for the complete cable length. Moreover, both piggyback cable and terminations must withstand the axial load due to elongation of the pipeline of the order of 0.1%–0.2%. This may correspond to an axial load at the terminations exceeding 10 tons. The termination design for Kristin DEH is shown in Fig. 18.

Until now, DEH has been installed on four projects with an accumulated cable length exceeding 100 km. Both Åsgard and Huldra have gained operational experience, while Kristin and Urd are currently being commissioned (mid 2005). The Huldra DEH system has been in use approximately 40 times since commissioning, May 2002. The Åsgard DEH systems were commissioned September 2003 and have been operated at around ten times. Generally, the experience with DEH is good. Most of the problems encountered originate from the installation and commissioning phase of the projects. In this phase, some rectification and improvement works have been required. After the systems have been handed over to the operation group, no major problems have been experienced. During the first three months after Huldra DEH was put in service, some problems with shut-down of DEH due to inadvertent protection relay trip were experienced. All these trips were caused by the overcurrent protection system. When these incidents were further investigated, it was concluded that the setting of the overcurrent protection was too narrow to handle voltage fluctuation during start and stops of large motors in the power network. The setting of the overcurrent protection settings was revisited and adjusted based on measurements of the fluctuations, and no shut-downs have taken place since. The design and operation of Huldra DEH are further described in [8]. Testing on the installed DEH systems has verified the rating and thermal performance of the systems. Measured parameters have shown to be in good accordance with basic theory and system calculations. C. New Projects and Further Developments Since the general qualification of the DEH concept was performed prior to the project Åsgard, a more or less continuous development of DEH has taken place. The combination of new technology elements not covered by the initial DEH qualification and of work initiated to improve the concept has caused subsequent projects to perform further DEH development. Currently, the project Tyrihans is being developed. DEH for Tyrihans is a significant technology step compared to previous projects. Parts of the technology development for Tyrihans DEH have been described in this paper. Installation of Tyrihans DEH is scheduled for 2007. Further DEH development will focus on widening the application area for the system. Development programs have been defined and partly initiated to cover the following. • Deep water application—Projects on the Norwegian Continental Shelf and elsewhere in world require DEH cables for greater water depths than currently qualified (500 m). • Longer pipelines—Tieback of subsea developments to shore or nearby platforms may employ DEH pipelines with lengths of several hundred kilometers. • Larger pipe diameters—Application of DEH for pipelines with diameters of 30 in or more is expected. • Retrofit installation—Installation of DEH on existing and future pipelines in case of an emergency situation (plug removal operations). For future pipelines where heating is

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not considered necessary, the pipelines may be prepared for DEH (but no cables are installed). Most of the above items are directly addressed to the piggyback cable in order to document the feasibility for a new application area.

The authors would like to thank Dr. B. Gustavsen and Dr. S. Hvidsten of SINTEF Energy Research for doing the calculations of screen voltages and for compiling the test results on semi-conductive sheath materials, respectively.

VII. C ONCLUSION

R EFERENCES

Electrical heating of thermal insulated pipelines for the prevention of hydrate formation and wax deposition in subsea oil production has proven to be economically feasible. Several concepts have been evaluated. After several studies and research projects, the DEH system has been selected as the preferred solution. In DEH, the electric current flows in the pipeline wall, generating ohmic losses within the pipeline. The heating system is galvanically connected to the surrounding sea water through sacrificial anodes. Finite-element calculations are performed to calculate the electric system parameters and to rate the system. In the current transfer zones of the pipeline, additional anodes (aluminum) are needed to keep the current density low in order to control added ac corrosion of the conventionally applied pipeline (dc) anodes. In addition, the anodes must be located close to each other to avoid corrosion of the pipeline itself, should a crack in the thermal insulation occur within this zone. Magnetic permeability and electrical conductivity are not controlled material parameters at steel works. The magnetic permeability has been shown to vary even between individual pipe joints from the same production batch. It is therefore necessary to measure these material properties on individual pipe joints and sort them into groups. The pipe joints in each group are then joined together to form sections. At the intersection between different sections, extra grounding anodes are needed due to the current transfer caused by the step change in magnetic permeability. For long pipelines, the original piggyback cable’s screen-toground voltage becomes unacceptable. Different methods for solving this problem have been evaluated. For the Tyrihans development, a new cable design with a semi-conductive outer sheath has been adopted. After testing several candidate materials, a prototype cable rated to 52 kV has been manufactured. The ongoing qualification program is scheduled to be completed in December 2005. Detection of a cable fault (ground fault) close to the far end of the piggyback cable has shown to be difficult with traditional protection methods. A ground fault that is not cleared may ultimately compromise the integrity of the pipeline. An alternative for fault detection in this region is currently under development. Since the year 2000, the DEH system has been installed in four field developments on the Norwegian Continental Shelf. On the first two (Åsgard and Huldra), the DEH systems have been used approximately 50 times. Measured values for system impedance and generated pipeline heating agree well with calculated values. Future development of the system will focus on deeper water, longer and larger pipelines, and the possibility for retrofit installation of the system.

ACKNOWLEDGMENT

[1] F. Aarseth, “COMBIPIPE: A new dimension in offshore field development and design of subsea transportation systems,” in Proc. Advances in Subsea Electrics and Electronics, London, U.K, Jun. 1995. Subsea Engineering News. [2] FLUX V8.1D, CEDRAT, Meylan, France, Jun. 2004. [3] H. Faremo, B. E. Knutsen, and J. A. Olsen, “12 and 24 kV XLPE cables in Norway. Faults related to water treeing,” in Proc. CIRED, 1993, pp. 3.10/1–3.10/5. [4] H. Ilstad et al., “Continuous trawl protection of heating cable for direct electric heating,” in Proc. 24th OMAE, Halkidiki, Greece, Jun. 2005, pp. 669–674. [5] L. M. Wedepohl and D. J. Wilcox, “Transient analysis of underground power-transmission systems,” Proc. Inst. Electr. Eng., vol. 120, no. 2, pp. 252–259, Feb. 1973. [6] B. Gustavsen, “Validation of frequency dependent transmission line models,” IEEE Trans. Power Del., vol. 20, no. 2, pp. 925–933, Apr. 2005. [7] S. Hvidsten et al., “HV cable design applicable for direct electrical heating of very long flowlines,” in Proc. 15th ISOPE, Seoul, Korea, Jun. 2005, vol. 2, pp. 44–48. [8] O. Urdahl et al., “Operational experience by applying direct electrical heating for hydrate prevention,” presented at the Proc. OTC, Houston, TX, May 2003. Paper OTC 15189.

Arne Nysveen (M’00) received the M.Sc. degree in electrical power engineering and the Dr.Ing. degree from the Norwegian Institute of Technology (NTH), Trondheim, Norway, in 1988 and 1994, respectively. From 1995 to 2002, he was a Research Scientist with ABB Corporate Research, Oslo, Norway, where his main research dealt with subsea power supply and electrical power apparatus. Since 2002, he has been a full-time Professor with the Department of Electrical Power Engineering, Norwegian University of Science and Technology (NTNU), Trondheim. He holds several patents on subsea power equipment and electric machinery.

Harald Kulbotten received the M.Sc. degree in electrical power engineering from the Norwegian Institute of Technology (NTH), Trondheim, Norway, in 1975. Since 1976, he has been a Research Scientist with SINTEF Energy Research, Trondheim. He holds a key position in the development work of pipeline heating on several projects in the North Sea. He has written several papers on fire protection of electrical installations and electrical heating of pipelines. His main research activities have dealt with fire protection of electrical installations, electromagnetic compatibility, design of power distribution systems for industry and marine applications, electrical installations on ships, and electrical pipe heating systems for subsea pipelines.

Jens Kristian Lervik received the M.Sc. degree in electrical power engineering and the Dr.Ing. degree in electrical engineering from the Norwegian Institute of Technology (NTH), Trondheim, Norway, in 1975 and 1988, respectively. His Dr.Ing. thesis was on the topic “calculation and measuring methods of induced losses for high current installations.” Since 1976, he has been with SINTEF Energy Research, Trondheim, where he was a Research Scientist on electric power technology and has been a Senior Research Scientist since 2002. His main research during recent years has been on thermal and mechanical design of electrical high current installations and heating systems for subsea pipelines.

NYSVEEN et al.: DEH OF SUBSEA PIPELINES—TECHNOLOGY DEVELOPMENT AND OPERATING EXPERIENCE

Atle Harald Børnes received the M.Sc. degree in electrical power engineering from the Norwegian Institute of Technology (NTH), Trondheim, Norway, in 1990. Prior to his current position, he was with the hydroelectric power industry. Since 1992, he has been with Statoil ASA, Stavanger, Norway. He is currently a Specialist in pipeline heating and has been a key person in all pipeline heating projects since 1997. He has written several papers on electrical motor drives and pipeline heating and holds patents within the field.

Martin Høyer-Hansen received the M.Sc. degree in high-temperature superconductivity in 2003 from the Norwegian University of Science and Technology (NTNU), Trondheim, Norway, where he is currently working toward the Ph.D. degree in the Department of Electrical Power Engineering. His subject is direct electrical heating of subsea pipelines aimed specifically at studying current distribution and electromagnetic fields in the vicinity of the pipe.

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Jarle J. Bremnes received the M.Sc. degree in electrical power engineering from the Norwegian Institute of Technology (NTH), Trondheim, Norway, in 1992. From 1992 to 1997, he was a Research Scientist with ABB Corporate Research, Oslo, Norway. He has been working with offshore and subsea motor drives and power systems since 1996 and DEH systems since 2000. Since 2003, he has been a Senior Engineer with Nexans Norway AS, Halden, Norway.