NEW SUBSEA PROCESS COOLER; PART I: FOCUSED ON FLOW ASSURANCE, OPERATION AND RELIABILITY

NEW SUBSEA PROCESS COOLER; PART I: FOCUSED ON FLOW ASSURANCE, OPERATION AND RELIABILITY Stig Kanstad, Julien Rolland, Vivian Lyngvaer Framo Engineering, a Schlumberger Company, Caroline Boe, Henning Bodtker Statoil ASA Page 1 of 15

Abbreviations: T 1 : Compressor suction temperature [ o C] T 2 : Compressor discharge temperature [ o C] p 1 : Compressor suction pressure [bara] p 2 : Compressor discharge pressure [bara] v dome : Velocity in dome [m/s] Δp pipe : Pressure drop across cooler pipe [bar] ρ : Density [kg/m 3 ] η p : Polytrophic efficiency [-] Introduction: Artificial lift systems in common with gas lift or down hole single phase pumps have been used for generations in the oil industry. The main benefits from artificial lift systems are that the field can be depleted faster or the life time of the wells increased with a higher recovery and longer tie backs than traditional production methods. Artificial lift based on multiphase pumping technology has matured during the last couple of decades and is now established as proven technology. Multiphase pump stations located at sea bed or topside are now an alternative to and often combined with down-hole pumps and gas lift systems. The next step for artificial lift systems is subsea wet gas compression. Framo Engineering has been working with wet gas technology since the late 80s and Framo Engineering and Statoil has in recent years cooperated in developing and qualifying a subsea wet gas compressor station which will be installed at The Gullfaks field in the North Sea as part of the Gullfaks 2030 program. The Gullfaks wet gas compression program and the qualification testing of the wet gas compressor is presented in /1/. Early in the technical qualification program it became apparent that subsea cooling was mandatory for the success of a subsea wet gas compression system due to high suction temperatures together with the inherent temperature increase across the compressor. It was also evident that cooling was beneficial as lower suction temperatures will increase the suction fluid density and decrease the volumetric flow rate hence allowing a higher and more efficient energy input into the process fluids. A cooler has been built to full specifications and tested in order to validate both production methods, mechanical and thermal performance. The thermal performance of the free convection cooler developed in the technical qualification program is presented in /2/. System description: Figure 1 shows a simplified process flow diagram for the subsea wet gas compression station giving an overview of how the cooler interacts with the rest of the wet gas compression station and the complete production system. Page 2 of 15

Figure 1: Process flow diagram schematic (one train) The Compression Station main components consist of wet gas compressors with individual recirculation systems, process coolers, a flow mixer and a bypass header. The flow mixer is located at the inlet of the station and the main purpose of this device is to dampen out liquid slugs and provide an equal homogenous split of multiphase flow to the two compressors when operating in parallel. The temperature increase across a compressor is a function of the pressure ratio, fluid properties and efficiency (eq. 1). The main purpose of the cooler is to cool the well stream before compression, in order to allow a high pressure ratio across the compressor without the discharge temperature rising above the flow line design temperature. (1) The production fluid first encounters the bypass header where the flow is either routed through the main bypass (V3 is open and V1 and V2 are closed) or through the compressors (V3 is closed and V1 and V2 open). The production fluid will then, if routed through the compressors, first encounter a mixer which will dampen out slugs and provide an equal split between the two compressors if running in parallel. The flow is then cooled in the coolers and compressed in the compressor before being routed back into the flow line towards topside. The compressor station is, as can be seen from Figure 1, also equipped with a re-circulation line routing, if required, some of the flow from downstream the compressor back to upstream the cooler. The function of the re-circulation line is to increase the flexibility of the system. The re-circulation line in combination with the coolers also enables the system to run at full re-circulation without overheating while drawing down the suction pressure in order to start up dead wells. Cooler description: The cooler module, located upstream the compressor, is a retrievable unit that consists of 8 off basic cooler units or bundles with a fluid distribution at the top and collecting system at the Page 3 of 15

bottom inside a support frame. A schematic of a cooler module arrangement is shown in Figure 2. Note that the number of cooler units in a cooler module depends on the cooling requirement for the actual application. Figure 2: Schematic of cooler module with 8 cooler units The cooler units or bundles consist of 33 vertical pipes in parallel between an upper distribution dome and a lower collector dome. The cooler unit is shown in Figure 3. Page 4 of 15

Figure 3: Cooler bundle cross section The main parameters for the cooler module are: Design pressure: 390 barg Design water depth: 500m Design temperature: 0 o C to +120 o C Number of cooler bundles: 8 bundles Footprint: 4.1m x 4.9m Height: 8m Cooling capacity 5.5 MW Area margin 30% (Gullfaks conditions) Free versus forced convection: The cooler design is based on free convection on the external side and forced convection on the process side. This is to fulfil the requirement that subsea equipment should preferably be kept as simple and robust as possible due to limited access for inspection, maintenance and repair. A subsea design should hence be based on what is not there, cannot fail. Auxiliary equipment, complex control systems, etc should hence only be used if absolutely required. Page 5 of 15

Fluid distribution: Significant variations in the fluid distribution could cause problems with cooling capacity, wax, scale hydrates etc. An even fluid distribution between cooler pipes or cooler units will ensure that all pipes and hence all cooler units will have the same temperature profiles. An equal fluid flow distribution between different cooler units and between individual pipes in each cooler unit is hence mandatory. The main parameter to ensure a good fluid distribution is to ensure that all flow paths through the cooler modules have the same pressure losses. Any pressure difference between two parallel flow paths will cause an uneven fluid distribution between the two paths. The focus when designing a system with an equal split between several parallel flow paths is hence on symmetry from where the flow is split and until the flow is remixed. In addition, for multiphase flow, it is important to ensure that the layout of the piping is such that there are no significant tendencies for an uneven gas-liquid distribution between the parallel pipes when splitting the flow. The gravity effect due to the large density difference between gas and liquid must hence be taken into account when designing a multiphase fluid distribution system. The angle between pipes should thus be selected such that gravity effects are minimized when splitting the flow. The velocity in the fluid distribution system upstream the cooler units should in addition preferably be high enough to prevent fluid separation and a well mixed fluid without resulting in large pressure losses. The fluid distribution and collection system for the cooler module is shown in Figure 4. Outlet Inlet Figure 4: Schematic of fluid distribution and comingling system Page 6 of 15

The process flow is, as can be seen from Figure 4, routed from the flow mixer into the cooler module inlet and then up into the centre of the cooler module where it encounters a fluid distribution block such that the fluid is distributed symmetrically between four legs. The angle between the inlet and pipe and the four legs is larger than 90 o making the four legs tilt downwards in order to minimize gravity effects on the gas-liquid distribution. Each of the four legs is then split symmetrically in a T before entering the separate cooler units. The fluids leaving the cooler units are mixed in the T s before the flow is routed into the mixing block and routed out of the cooler towards the compressor. Note that there is, as for the cooler inlet section, a downwards slope towards the cooler module outlet. The above described cooler module consists of 8 cooler units. Figure 5 shows schematically a few alternative cooler unit arrangements inside a cooler module still maintaining a symmetric fluid distribution and collecting system. The cooling capacity of a cooler module can hence be tailor made for different field applications or for changing cooling demand for a specific field by adjusting the number of cooler units used in a cooler module without adverse effects on the fluid distribution and mixing system. Figure 5: Alternative cooler module configuration with 4 coolers An equal fluid flow distribution between individual pipes in each cooler unit is, as for the fluid distribution between cooler units mandatory. An even fluid distribution between the individual cooler pipes in the cooler unit is obtained by keeping the pressure drop across each pipe significantly larger than the dynamic pressure in the inlet dome (eq. 2). This is achieved by using a nozzle plate. (2) Figure 6 shows a schematic of the cooler unit inlet section with nozzle plate. Page 7 of 15

Figure 6: Fluid distribution inside cooler unit An even fluid distribution between cooler units and between individual cooler pipes in each cooler unit is hence ensured by the cooler fluid distribution design. Flow assurance and reliability: Flow assurance is a relatively new term in the oil and gas industry coined by Petrobras in the early 1990s. The term was initially reserved for thermal hydraulic and production chemistry issues encountered during oil and gas production /3/. It refers to ensuring successful and economical flow of hydrocarbon stream from reservoir to the point of sale. The term has however broadened to cover more or less any issue that can affect the extraction of oil and gas. The main topics for the cooler have been flow assurance issues such as systems regularity, reliability, regulation and risk management, in addition to the traditional flow assurance issues such as transient multiphase flow, wax, scale, hydrates and solids management. Off design operation: The production flow rate and hence the cooling requirements will over time vary significantly from the design cases. Basing the cooler on free convection on the ambient side will automatically regulate the cooling capacity versus the process fluid temperature. This is because the magnitude of the free convection heat transfer is directly linked to the difference between the external wall temperature and the ambient sea temperature. Consequently, the cooling capacity is low if the process fluid temperature is low and the cooling capacity high if the process temperature is high. Any forced convection (sea current) will result in a mixed (free plus forced) convection on the ambient side systematically shifting the overall heat transfer coefficient to a higher value. A method for regulation and control with the station cooling capacity is hence required. The compressor energy inputs into the process fluid will, when burnt across a choke be dissipated as heat. The selected regulation method is hence based on controlling the cooler inlet temperature and hence the cooler outlet temperature by changing the re-circulation flow rate according to needs. Large permanent changes in the cooling requirements can in addition be mitigated by changing the number of cooler units in the cooler module. Hydrates: Gas hydrates are a type of clathrates /4/. That is, there is a grid of water molecules creating cages in which small guest molecules, typically methane, ethane and propane can be trapped Page 8 of 15

forming an ice like structure at temperatures and pressures often encountered in a production system. A typical phase envelope is shown in Figure 7. 200 180 160 140 Pressure [bara] 120 100 80 60 40 20 0 0 5 10 15 20 25 Temperature [degc] Fresh water 25% MEG 50% MEG Figure 7: Typical hydrate formation curves Hydrates may cause severe operational challenges for a production system if formed due to blocked lines and danger to both personnel and production system when trying to remove the plug(s). Caution is hence taken both during the design and production phases in order to keep the system out of the hydrate region. This is typically achieved by using inhibitors to shift the hydrate formation curve towards lower temperatures and by using insulation in order to keep the process fluid temperature high during production and to slow down the cool down process. The cooler module will due to its purpose be a major cold spot which will cool down to ambient sea temperature within minutes after a shut down or a black out (Figure 8). Page 9 of 15

70,0 60,0 50,0 Temperature [degc] 40,0 30,0 20,0 10,0 0,0 0,0 0,5 1,0 1,5 2,0 2,5 3,0 3,5 4,0 4,5 5,0 Time [min] Fluid density = 50 kg/m3 Specific heat capacity = 2000 J/kgK Overall heat transfer coeffcient = 200 W/m2K [degc] Fluid density = 50 kg/m3 Specific heat capacity = 2000 J/kgK Overall heat transfer coeffcient = 300 W/m2K [degc] Fluid density = 50 kg/m3 Specific heat capacity = 2000 J/kgK Overall heat transfer coeffcient = 400 W/m2K [degc] Figure 8: Typical cool down time versus overall heat transfer coefficient for a cooler pipe The system design must hence ensure that temperatures during production can be kept above the hydrate formation temperature. Zero or insignificant amounts of hydrates should be formed during a black-out. Furthermore, hydrates, if formed must be easily removed. The hydrate formation curve is known for an actual field and the cooler discharge pressure and temperature is either measured at the cooler module or at compressor suction a few metres downstream the cooler. The margin between the operating conditions and the hydrate formation curve is hence known. Hydrate prevention during normal operation: Three different strategies can be used when the cooler discharge conditions come too close to or inside the hydrate formation zone. The hydrate formation zone could be moved by continuous dosage with hydrate inhibitor from immediately upstream the cooler. The flow rate through the re-circulation line can be increased, increasing the cooler inlet and discharge temperature hence moving the process condition out of or further away from the hydrate formation zone. Alternatively a combination of the two could be used. Hydrate removal: The total flowing cross section of the cooler units is much larger than the piping cross section. A gradual build up of hydrates in a cooler pipe will hence over time, as the blockage degree increases, reduce the flow rate in that pipe and increase the flow rate in the neighbouring pipes/cooler units. The build up will hence, at the latest, be detected though increased suction temperature and reduced suction pressure for the compressor prior to the cooler being completely blocked. Page 10 of 15

The station is equipped with several methods for hydrate removal from a partly blocked cooler. The compressor may be shut down and the cooler flooded with hydrate inhibitor in order to melt any hydrate blocking the system. The cooler pipe orientation will ensure that hydrate inhibitor will reach the hydrate front even for fully blocked pipes. The compressor can be run in re-circulation mode while injecting hydrate inhibitor. This will ensure that hydrate inhibitor will be in directs contact with the hydrate plug even for a fully blocked pipe while the energy input into the compressor can be used to increase the process temperature to help with melting the plug/deposits. The compressor can also be used to draw down and reduce the pressure inside the cooler to further enhance melting. It should be noted that the pressure drop across the cooler will be low, even with a partial plugging. There will hence be no significant pressure difference across the plug. It should be noted that removing a hydrate plug could be time consuming even if the system is depressurised and hydrate inhibitor is brought in direct contact with the plug. The focus for the system design has hence been on preventing hydrates to form. Hydrate prevention in case of a blackout: The cooler module is also protected against hydrate in case of a blackout as the wet gas compressor station operates at high gas volume fractions. The maximum amount of liquid in the cooler is hence substantially less than the volume of the adjacent piping in which it will be drained within seconds after a shut down. The water will thus be isolated from the gas by a condensate blanket and there will be no further stirring or mixing of the fluids. Hydrates, if formed are thereby expected to appear only as a thin ice layer. The volume ratio of liquid versus pipe is furthermore such that it is not possible to block the pipe even if all the liquid changes to hydrates. The collector pipe is in addition equipped with an injection point for hydrate inhibitor allowing inhibition directly in the liquid phase during shut down or after a blackout. The collector piping may, if required, also be insulated in order to slow down the liquid cooling rate. Hydrates can hence be prevented from forming during normal operations or blackout and can furthermore, if formed, be easily and safely removed. Sand: Most of the world oil and gas production comes from sand stone reservoirs /5/. Sand is hence a common bi-product in oil and gas production. Sand will be produced when the reservoir sandstone is weak enough to fail under the in situ stress conditions and the imposed stress changes due to the hydrocarbon production. Sand production is nearly always detrimental to a production system. The well itself may be blocked if the velocity in the tubing is insufficient to bring the sand to the surface. Sand will cause erosion and may be deposited in low velocity zones causing blockage if velocities are sufficient to transport sand up the tubing. Sand will, for the cooler, cause erosion in high velocity sections and blockage in low velocity sections if not handled correctly. The sand handling philosophy for the cooler is that any sand reaching the cooler shall be produced through the cooler. The dimensions of the distribution and mixing piping are hence selected such that the velocities are equal to or higher than in the piping upstream the cooler but low enough to avoid significant erosion. All low velocity sections, i.e. the cooler unit inlet and outlet domes and the cooler pipes are self draining and the dimensions of the cooler pipes have been selected in order to prevent sand blockage. Page 11 of 15

Sand will hence neither block, nor cause erosion damage to the cooler module. Wax: Wax is a common term used for long chained paraffins that tend to crystallize and deposit on a pipe wall if the temperature is lower than the wax appearance temperature. Wax, if present may be a flow assurance issue as wax deposits on the pipe wall will over time gradually reduce the pipe diameter hence increasing the pressure drop and in the worst case, if no corrective measures are taken, block pipes. Wax deposits in the cooler will reduce the overall heat transfer until the cooling capacity is such that corrective measures are required. The common solution for wax removal i.e. pigging cannot be used for the cooler module. The main method for wax removal is hence periodically melting wax deposits inside the cooler by heating. The heating is performed by running the compressor in partly or full re-circulation mode raising the temperature to a level where the wax is melted. The cooler is in addition equipped with a hot stab allowing the use of solvents if required. Significant amounts of wax are not expected in connection with wet gas compressor applications. The cooler module design allows however wax to be easily removed. Scale: Mineral deposits from dissolved salts dropping out of the water are commonly known as scale. Scale is a common problem in connection with produced water, heat exchangers etc and is known to able to completely block large pipe lines within hours under the right conditions. The solubility of ions will amongst other things change with pressure, temperature, ph and concentration of other ions. Dissolved solids can be characterised as normal soluble, i.e. increased solubility with increased temperature or inverse soluble. Inverse soluble salts may reach a maximum solubility value at a certain temperature above which the solubility will start to decrease. Scale will, under the correct conditions form on both the ambient and process side of the cooler. Scale fouling will, for the cooler, mainly be detrimental to the overall heat transfer and hence the cooling capacity. Scale deposits will, if occurring, gradually build up on the cooler pipes over time reducing the cooler efficiency until the cooling capacity has been reduced to such a level that intervention is required. Scale on ambient side: The inversion point for calcium scale is typically around 30-40 o C but the change in solubility is usually small below 60 o C /6-9/. The sea water is not expected to be saturated. Some scale deposits are however expected on the ambient side due to temperature effects (inverse soluble minerals, CaSO 4, CaCO3) and the cathodic protection system. The cooler is hence designed to have a low wall temperature on the external side. Typically maximum wall temperatures (depending on the inlet conditions) are less than 60 o C. The cooler can me retrieved for topside cleaning. Scale on process side: The scaling potential on the process side depends on the composition of the produced water. The gas from the reservoir is usually saturated with water resulting in water condensing as the pressure and temperature are decreased. The scaling potential inside the cooler is hence, in general low due to the produced water being diluted by condensed water reducing the Page 12 of 15

saturation levels. The cooler module is however equipped with hot stabs allowing the cooler to be washed with acids on the process side in order to dissolve scale. The cooler module can be retrieved to topside for cleaning if required. The cooler is hence designed for handling scale. Marine growth: Marine growth refers to marine species that attach to and grow on ships, marine infrastructures etc. often causing problems for their function. The cooler will, due to the initially low surface temperatures and the current created by the cooler be an ideal location for colonisation. Marine growth or fouling may, depending amongst other on water depth gradually build up on the cooler pipes. Marine growth on the cooler will be detrimental to the overall heat transfer and hence the cooling capacity of the cooler. The cooling capacity will be gradually reduced until intervention is required. The cooler is hence equipped with an ROV operated cleaning system on ambient side. The cooler module can in addition be retrieved for topside cleaning. The cooler design has a built in solution for solving marine growth fouling. Asphaltenes: Asphaltenes are a class of components of hydrocarbons that are insoluble in low boiling n- alkanes and soluble in toluene. Asphaltenes are the heaviest and most polar components in crude oil with molecular weight ranging from 500 g/mol up to more than 5000 g/mol. Asphaltenes may if flocculating form hard sticky lumps that will, if sticking to the wall, reduce the overall heat transfer and may even block the pipes completely. The solubility of asphaltenes in a fixed composition crude oil is typically at its minimum at the bubble point. The phase envelopes for retrograde gas fields and wet gas fields are typically such that the reservoir conditions are to the right of the critical point. Asphaltene flocculation and deposition is hence not expected to be a challenge for such fields. Asphaltenes are hence not expected to form in the cooler module. The cooler module is however equipped with a hot stab allowing the use of solvents if required to remove asphaltenes deposits and the cooler module is in addition retrievable for topside cleaning. Asphaltene fouling removal is hence built into the cooler design. Conclusion: Cooling is mandatory for the operation a subsea wet gas compressor system. Reliability and robustness must be the main focus when designing a subsea cooler. The pressure drop across the cooler must be kept low in order to maximize the pressure increase across the wet gas compressor station. The cooler design has hence been based on free convection on the ambient side in order to allow for easier inspection and maintenance while at the same time reducing the need for auxiliary equipment such as seawater circulation systems. The configuration of the cooler units with the symmetric distribution and collection system together with low velocities in the cooler units ensures that the pressure drop across the cooler is minimized while at the same time ensuring a good fluid distribution. The temperature inside the station can, due to Page 13 of 15

interaction between the cooler and the rest of the system be increased by increasing the recirculation rate. Re-circulation can thereby be used to prevent wax and hydrates building up and clogging the system. Wax and hydrates can also, if formed, be removed by re-circulation induced heating. The vertical self draining orientation of the cooler pipes prevents sand accumulation while at the same time ensuring that hydrate inhibitors can be brought into contact with a hydrate plug if formed. Hot stabs can be used to flood the cooler module with acid for scale removal if required or for hydrocarbon displacement prior to intervention. The. The re-circulation line can also be used to adjust the cooler suction temperature when operating at off-design conditions. The above discussion shows that the cooler design and the way the cooler can interact with the wet gas compressor station enables the system to handle sand, wax, scale, hydrates, marine fouling etc. The system has built in capabilities for mitigating actions, such that the operators can eliminate problems when required, thus increasing the availability of the cooler and hence the whole compressor station. Acknowledgements: We would like to thank Statoil and Framo Engineering (a Schlumberger company) management for permission to publish this paper. Page 14 of 15

References: [1] World first submerged testing of Subsea Wet Gas Compressor Knudsen T., Solvik N. Offshore Technology Conference, Houston, May 2011 [2] New Subsea Process Cooler; Part II: High Thermal Performances and Complex 3D Free Convection Heat Transfer Rolland J., Kanstad S., Lyngvaer V. Deep Offshore Technology International, Perth, November 2012 [3] The flow assurance dilemma: Risk versus cost Dr. martin Watson, Dr. Paul Pickering and Dr. Neil Hawkes [4] Natural gas hydrates in flow assurance Dendy Sloan, Carolyn Koh and Amadeu K. Sum Gulf Professional Publishing [5] Oil well sand Production control Maryam Deghani The 1 st International Applied Geological Congress, Department of Geology, Islamic Azad University Masad Branch, Iran 26-28 April 2010 [6] Problems facing the designer of offshore heat exchanger M. A. Taylor British National Oil Company London England [7] A method for predicting the tendency of oil field waters to deposit calcium sulfate Henry A. Stiff and Lawrence E. Davis Petroleum Transactions AIME 1952 [8] Mechanism of Calcium sulfate scale deposition on heat-transfer surfaces David Hansson and Joseph Zahavi I & EC Fundamentals 1970 [9] Fouling: The major unresolved problem in heat transfer J. Taborek, T. Aoki and J. W. Palen Chemical engineering progress 1968 Page 15 of 15