OTC MS. Abstract

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1 OTC MS Benchmarking and Dynamic Simulation of Direct Electrical Heating (DEH) Operations in a Subsea Flowline C.E. Rawsthorne, BP Norge, A.R. Hall, BP Exploration Operating Company Ltd., H. Dong, OneSubsea Copyright 2015, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 4 7 May This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Direct Electrical Heating (DEH) was implemented on a 12 13km subsea wet gas tieback flowline to assist in thermal and flow assurance management during start-up and shut-down of production. The performance of the DEH system was critical for hydrate management in the single flowline configuration. However, it was very difficult to model the DEH system for the large scale pipeline due to the constraints of computational speed. It was also difficult to determine the DEH performance due to the absence of temperature gauges within the DEH zone of the flowline. Based on the first available field data, the study was able to find a way to investigate the DEH performance using the pressure increase at the subsea template and riser top. A dynamic simulation model was then developed to match the DEH performance during both the heat-up process and heatmaintain process. This enabled further optimization of the operating procedures for the DEH system based on dynamic simulations run using the tuned and benchmarked thermohydraulic model. The results showed that the DEH performance calculated from the pressure response was better than predicted during the design phase. The DEH heating process was well matched by the dynamic simulation in terms of pressure and temperature response in the flowline. The study demonstrated a novel way to determine the DEH performance for a subsea pipeline based on basic fluid dynamic theory. It demonstrated the applicability of dynamic thermohydraulic simulation tools to replicate the DEH heating process at the scale of the entire subsea flow line under both steady state and transient operating conditions, which is important to the development of operating guidelines. The optimization of operating procedures with the dynamic simulation results resulted in reduced heat-up times (and thereby reduced production deferment) and minimized the hydrate formation risks during system shutdown and restart. An example was provided for future projects on how to use and optimize DEH operation to assist flow assurance management. 1.0 Introduction This DEH system is a global first application for the oil and gas operator in terms of design, installation and operation of direct electrical heating. For this reason there was a strong interest in the development of a dynamic thermohydraulic model which could confirm the performance of the heating system in terms of absolute temperature increase imparted to the system fluids subsea. As there are no temperature measurements in the subsea flowline sections covered by DEH it was necessary to develop a performance management process which made use of available pressure indicators at either end of the pipeline. These measurements and the inferred temperatures could then be used to build and tune a dynamic thermohydraulic model of the system.

2 2 OTC MS 2.0 System Description The gas field had a Gas Initially In Place (GIIP) of 17.2 GSm 3 at a reservoir pressure of 374 bara and temperature of 126 C. The gas is relatively dry, with a Condensate to Gas Ratio (CGR) of 48.1 Sm 3 /MSm 3. The field has been developed through the installation of a 4 slot subsea template, currently with 2 producing wells, with a maximum production rate of 153 ksm 3 /h per well. The template is connected via a single 13km 12 rigid carbon steel production flowline with internal Corrosion Resistant Alloy cladding, and a 10 flexible production riser, to a Floating Production, Storage and Offloading vessel (FPSO) in approximately 350m water depth. The 12 flowline is equipped with wet insulation and Direct Electrical Heating (DEH) in the form of a piggyback cable to the pipeline. There are no pressure or temperature gauges along the length of the 12 production flowline. However, pressure and temperature measurements are available at both the subsea template manifold, and the riser top at the FPSO. The DEH system comprises a riser cable, armored feeder cable and piggyback cable. The piggyback cable is strapped to the production flowline over its 13km length. Alternating Current is passed through the piggyback cable to the far end of the flowline, where the two are terminated together. The steel flowline wall then acts as a return conductor. Heat is generated by resistive current losses in the flowline wall. Topside hang-off and power work Flexible Production Riser DEH Coaxial Riser Cable Subsea Junction Box Coaxial Armoured Feeder Cable Piggyback Cable Figure 1: Simplified DEH System Configuration Pipeline Template The DEH system has 2 modes; Heat Up mode designed to heat the pipeline from ambient seabed temperature (approx. 6 C) to above Hydrate Equilibrium Temperature (HET) at maximum shut in pressure conditions (21 C), and Maintain Heat mode, designed to maintain the temperature of fluids in the pipeline above HET immediately following a production shutdown. Heat Up mode has a total power supply to the DEH cable of 2.2 MW, whereas Maintain Heat mode has 1.8 MW. 3.0 Benchmarking Data and Results During Initial Heat-up Process Pressure and temperature data were gathered during the initial start-up of the subsea system in October 2013 and have been used for tuning of the power required for input to the dynamic simulation model. The first step of the start-up process was to pre-heat the shut in pipeline from seabed temperature to above hydrate equilibrium temperature. Hence, during this process there was no production flow and the pipeline contents constituted a stagnant fixed volume of gas. This provided an excellent opportunity to benchmark the effectiveness of the heat-up process by examining changes to system pressure as heat was input to the system. There was no measurement of the flowline temperature at pipeline sections with DEH, thus there was no direct way to obtain

3 OTC MS 3 the fluid temperature during the heating process. However, the fluid in the flowline expanded during the heating and thus increased the flowline pressure. The pressure measurements at subsea and riser top could be used to calculate the temperature increase. In this case, the fluid properties in the flowline were a determining factor for the pressure-temperature calculations. The fluid properties were determined by the fluid composition and the in situ pressure and temperature conditions prior to the DEH operation. The flowline conditions during the use of DEH were important to simulate the heating process, but assumptions still needed to be made to simplify the process. The following assumptions were made: Flowline and riser filled with 30% Nitrogen and 70% Export Gas Topsides choke was closed during the DEH heating period Constant fluid volume in the flowline and riser Figure 2 shows the pressure measurement during the DEH heating process. The DEH was turned on around 17:00, Oct 18 th 2013, and continued for approximately 60 hours (corresponding to the heat-up time recommended by the vendor). After 60 hours the DEH was switched to maintain mode, which has a lower power consumption, while other start-up preparations were progressed on the FPSO. The system was then returned to heat-up mode prior to well start-up. The pressures at the subsea template and riser top increased correspondingly during the heating process, decreased when switched to maintain mode, and increased again when switched back to heat-up mode. Figure 2: Pressure Measurement during DEH Heating Process The fluid pressure would increase with the fluid temperature in a fixed volume during a heating process. The initial conditions for the fluid were 6 C and 38.3bara prior to heating with DEH. The pressure then increased with temperature according to the PT curve in Figure 3. The final pressure during DEH was 44.2 bara, corresponding to a final temperature of 41 C according to the P-T curve for the 30% Nitrogen, 70% export gas compositional mix.

4 4 OTC MS Figure 3: Fluid Pressure - Temperature Curve with Constant Volume 4.0 Transient Modelling of DEH Process using a Dynamic Simulation Tool Following a successful temperature benchmark by inference from pressure increase in the system, it was necessary to investigate if a dynamic simulation can successfully model the process, which was important for further optimization of DEH operating procedures. The modelling of DEH was performed using dynamic simulation software with the Electrical Heating module that existed within the software package. In the model, the heat was provided to the steel pipe concentrically surrounding the fluid and the model assumes that the specified energy was input into the system in a concentric way. This is different to the real system where some of the power supply is lost to the surrounding environment, and some heat is provided radially from the DEH piggyback cable itself, and thus the heat input is not concentric. This is illustrated in Figure 4. Heating location in Model Heating locations in Real System Figure 4: Difference in Heat Input Between Simulation Model and Real System In addition to modelling the heating, the DEH benchmark can also provide useful information on overall heating efficiency, i.e. the energy supplied to the system versus the total power consumption. The equation is shown in Equation 1. Equation 1: Definition of Heating Efficiency The temperature throughout the heating process was calculated from the subsea pressure, based on the P-T curve generated in Figure 3. Figure 5 shows the converted temperature from subsea pressure measurement. It can be seen that the temperature increased quickly during the first 24 hours after the DEH was started, and the increase gradually flattened out as the heat supplied by the DEH and heat loss to the environment reached equilibrium. This indicates that for a given power input the system will reach a fixed maximum equilibrium temperature.

5 OTC MS 5 It can also be seen that the temperature dropped when DEH was switched from heat-up mode to maintain mode, where the power supply was reduced from 2.2 to 1.8 MW. Temperature and pressure both increased again as the DEH was switched back to heat-up mode. Figure 5: Conversion of Subsea Pressure to Fluid Temperature In the dynamic simulation model, an energy supply was specified for the steel pipe in the unit of W/m. With the different power inputs, the temperature increased or decreased at different rates. A power matching exercise was carried out where different sensitivity runs were completed by varying the power supply. The power supply values in the simulation which gave the best match to the calculated system temperature increase were found to be 85 W/m for heat-up mode and 69 W/m for maintain mode. Using the matched power supply value, the transient DEH process was then simulated. The results are shown in Figure 6, where the simulated flowline temperature was compared with converted flowline temperature. It can be seen that the temperature trend closely followed the simulation throughout the process, including the period when the DEH mode switches occurred. This demonstrated that the thermal process from DEH could be successfully simulated in a transient manner. Figure 6: Simulated Temperature and Pressure Compared with Measurement

6 6 OTC MS As a result of the power matching exercise, the total simulated power supply indicated the effective power that was supplied to the system, and thus the heating efficiency was calculated as shown in Table 1. It can be seen that roughly 52% of power supply was actually effectively input into heating the flowline, while 48% of power supply was lost to the environment. Table 1: Heating Power Comparison between Simulation and Operation Input OLGA Total Power Total Power Heating DEH Mode Power, W/m OLGA, MW Supply, MW Efficiency % Power Loss % Heat up Maintain Achieving an Improved Pressure Match Between Simulation and Real System Although the dynamic simulation provided a good temperature match between measured (inferred) and simulated temperature increase, there was some offset in the simulated and real system pressure, particularly the pressure measurement at the riser top. It was confirmed that 5 m 3 of methanol had been injected into the riser prior to switching on the DEH. The liquid in the riser increased the fluid density and led to a higher differential pressure between subsea and riser. The amount of the methanol was distributed in the riser, jumper or flowline, however the exact location of the methanol was uncertain since the pressurization with export gas was carried out after the methanol injection. The methanol would accumulate at low points in the system at static conditions. Considering the riser and flowline geometry, there were two potential locations, the riser bottom and sag bend, that could have methanol accumulation, as shown in Figure 7. The methanol should initially accumulate at the sag bend and then could be pushed into riser bottom by the injected gas. Three different scenarios were simulated in the attempt to determine the location of the methanol: at sag bend, riser bottom and flowline jumper. The scenarios aimed at matching the pressure data during the heating process with the location of the methanol in the system. Potential methanol accumulation locations Figure 7: Geometry of Riser and Jumper A good match was found with the simulation which had the methanol located at the riser base. When the DEH was turned on, the differential pressure increase followed closely with the measurement. When the pressure increase in the flowline pushed the liquid up the riser, the liquid quickly reached the bottom of the U shape and thus the gas broke through. This stopped the continuous increase of the differential pressure between riser top and subsea. This phenomenon can also be observed by the response of the riser top pressure measurement as shown in Figure 8.

7 OTC MS 7 Figure 8: Simulated Pressure and Temperature Compared with Measured with Methanol Plug at Riser Base While the subsea pressure measurement was very smooth, the riser top pressure showed a lot of small variations. This can be explained by the liquid plug being pushed up the riser and gas periodically breaking through the liquid plug at the bottom of the riser. The simulated riser top pressure replicated similar pressure variations, giving an extremely satisfactory correlation between simulated data and real data. It was therefore possible to conclude that the methanol had accumulated at the riser bottom, and both pressure and temperature could be well matched by the simulation when the conditions in the flowline were simulated correctly. 6.0 Further Optimization Resulting from Simulations with Benchmarked Model Once the dynamic simulation model had been built, tuned and successfully benchmarked against real system data, it was possible to use the model to simulate a number of different scenarios which were of particular interest in the operating environment. The results of these dynamic simulations were then used to update operating practices and procedures, to ensure subsea system integrity, protect against hydrate formation, and minimize production downtime by reducing the time used in shutting down and restarting the system. 6.1 Case 1: Heating Times for Cold Pipeline It was possible to calculate the total heat-up time required to heat all sections of the subsea pipeline from ambient seabed temperature (6 C) to above Hydrate Equilibrium Temperature (25 C). To do this the dynamic simulation model was run with low production flowrate (to give high liquid holdup) and at normal operating pressure. The production was then shut down and the flowline allowed to cool to ambient temperature. The total liquid holdup and water holdup were significant for the low flow rate case. During shutdown, the liquid and water accumulated at the lower points in the pipeline. During heating, the sections that were filled with liquid (water) took a longer time to heat up than the gas filled sections. It was concluded that the ultimate fluid temperature reached and the time taken to heat to above HET depended on both liquid holdup and DEH mode used; the results are summarized in Table 2. It was discovered that it is also possible to use maintain heat mode to heat the fluid above HET, but this took 10 hours longer than the heat-up mode.

8 8 OTC MS Table 2: Summary of Final Fluid Temperature and Time to Heat above HET for DEH Modes DEH Mode Time to 25 C, hours Final Temperature, C Heatup Mode (gas) Heatup Mode (liquid) Maintain Mode (gas) Maintain Mode (liquid) These results were significant as they allowed an update to be made to operating procedures reducing the required heating time to 24 hours, from the 60 hours recommended by the DEH system vendor. This increases the operating efficiency of the system by reducing shutdown time prior to production restart. 6.2 Case 2: Use of Maintain Mode after a Shutdown on Riser Pressure HiHi This scenario was designed to examine the possibility of overpressuring the pipeline and riser system by turning on the DEH immediately after a high pressure trip had been activated. The concern was that by inputting heat to the system, the system pressure may increase further above the high pressure trip level. The dynamic simulation model was used to prove that this was not possible and there was no system integrity risk. The simulation was run with medium production rates and maximum system operating pressure. The production was then shut down and the DEH was turned on in maintain mode 4 hours after the production shutdown, in line with operating procedures. This scenario gave the highest operation pressure, which thus had the largest mass in the system if not considering liquid accumulation. Figure 9 shows the flowline temperature and pressure after the system shutdown at 175 bara. The system was run at 100kSm 3 /h for 24 hours. After the system was shut in at the 24 th hour, the flowline inlet pressure reduced from 200 bara to 190 bara and the riser top pressure increased from 177 bara to 185 bara. This was the resulting settle-out pressure after the frictional pressure drop had disappeared and the system achieved an equilibrium state. Figure 9: Flowline Pressure and Temperature after High Pressure Shutdown with DEH in Maintain Mode The fluid temperature started to decrease immediately once the system was shut-in, which resulted in a pressure decrease in the flowline. At hour 28, the DEH was turned on in maintain mode with the input power of 69 W/m. The temperature drop slowed down due to the additional heat from DEH. However, the temperature continued to fall as the high system temperature led to the rapid energy loss to the environment, and the heat supply from DEH could only slow down the

9 OTC MS 9 temperature drop. As there was no temperature increase, there was no corresponding pressure increase, and the system pressure continued to decline in line with the declining temperature. Thus it was concluded that there was no risk of over pressuring the system with heat input from the DEH. It can also be seen that the final temperature with the maintain mode was 34 C after a long time shut-in. This temperature was the flowline temperature which reached equilibrium with heat loss to the environment. If the system was heated from cold conditions for a long time, it would reach the same temperature, as reported in Case 1 above. 6.3 Case 3: Restart with Direct Electrical Heating after Producing at High Flow Rate The purpose of this case was to simulate a normal system restart from a cold, shut-in flowline, to examine the impact of Joule Thomson cooling across the subsea production well choke, and track the associated low temperature dip through the flowline system to the riser top. This is to ensure that the low temperature gas developed during a cold well restart did not pose a hydrate formation risk to the subsea system even after pre-heating with DEH. The simulation replicated a normal production shutdown and restart, with relatively high initial production rates and normal operating pressures prior to 7 days shutdown. The DEH was then used in heat up mode for 24 hours prior to restarting well production. The liquid holdup in the system varied depending on flowline topography, but was generally low (10 to 30%) due to the high production flowrate. The rate of temperature increase was dependent on the liquid holdup for any given location. During restart, the fluid temperature at the riser top first increased to 28 C (this value can change depending on DEH time) when the pre-heated fluid was produced out of the flowline, and then dropped below 20 C when the cold gas from the J-T cooling at wellhead arrived at topsides, then the temperature increased towards the steady state level. This is considered acceptable for hydrate management as there was maximum 2 C of subcooling under transient (flowing) conditions with very little water accumulation. The dynamic simulation model was therefore used to confirm the hydrate management strategy under a normal planned production shutdown and restart. 7.0 Conclusion This study has developed a novel way to benchmark DEH system heating performance using only pressure responses at either end of a subsea pipeline. The results show that the DEH thermal performance was better than that promised by the system vendor. The study was also able to demonstrate the applicability of a widely used dynamic thermohydraulic simulation tool to replicate the heating process and thermohydraulic behaviour of a large scale subsea pipeline system, both for steady state and transient conditions. The dynamic simulation model was then available as a resource to the engineering and operations teams to optimize operating procedures by reducing production deferment, minimizing power consumption, and quantifying any risks to system integrity and production. 8.0 Acknowledgements The authors would like to thank BP Norge A/S for permission to publish this material, and OneSubsea for their contribution to the dynamic simulation studies.