PRESSURE PROTECTION FOR AN OFFSHORE PLATFORM

Abstract

A method for pressure protection of an offshore platform (14, 16) of an oil and gas installation, the offshore platform (14, 16) being connected to source of hydrocarbons via a pipeline (18), the method comprising: using a safe link device (62) at the pipeline (18); wherein the safe link device (62) is located subsea and outside of the safety zone of the platform (14), (17); protecting the platform via a subsea High Integrity Pressure Protection System (HIPPS) for the platform (14, 16) and/or the pipeline (18); and wherein the safe link device (62) is arranged to activate to release pressure from the pipeline (18) when the pressure exceeds a preset threshold that is above the normal ultimate limit state pressure for the platform (14, 16).

Claims

1. A method for pressure protection of an offshore platform of an oil and gas installation, the offshore platform being connected to source of hydrocarbons via a pipeline, the method comprising: using a safe link device at the pipeline; wherein the safe link device is located subsea and outside of the safety zone of the platform; protecting the platform via a subsea High Integrity Pressure Protection System (HIPPS) for the platform 14, 16 and/or the pipeline 18; and wherein the safe link device is arranged to activate to release pressure from the pipeline when the pressure exceeds a preset threshold that is above the design pressure for the platform.

2. A method as claimed in claim 1, wherein the HIPPS is arranged to control the pressure to a lower level than the preset threshold for activation of the safe link device.

3. A method as claimed in claim 1 or 2, wherein the preset threshold is above the normal operating pressure for the platform and above the ultimate limit state pressure for the pipeline.

4. A method as claimed in claim 1, 2 or 3, wherein the preset threshold is below the maximum allowable accumulated pressure for the platforms and/or below the accidental limit state pressure for the pipeline.

5. A method as claimed in any preceding claim, wherein the safe link device is a physically triggered device including at least one of: a structure in the pipeline that is designed to burst at a set pressure, a valve with a breakable pin that will fail at the required pressure, or a rupture disc.

6. A method as claimed in any preceding claim, wherein the safe link device comprises a rupture disc that will break and release the pressure from the pipeline when the pipeline pressure exceeds the preset threshold.

7. A method as claimed in any preceding claim, wherein the safe link device is located 500 m or more from the platform.

8. A method as claimed in any preceding claim, comprising using multiple safe link devices for redundancy and/or wherein the safe link device comprises multiple pressure activated mechanisms for redundancy.

9. A method as claimed in any preceding claim, wherein the preset threshold is in the range 430-450 barg.

10. A method as claimed in any preceding claim, comprising arranging the platform such that there is no mechanism for emergency depressurisation of a hydrocarbon inventory of the platform in the event of a fire or other emergency that causes an over-pressure.

11. A method as claimed in any preceding claim, wherein the platform is an unmanned platform with no permanent personnel.

12. A method as claimed in any preceding claim, wherein the platform is an unmanned platform and has no provision of facilities for personnel to stay on the platform, for example there may be no shelters for personnel, no toilet facilities, no drinking water, no personnel operated communications equipment, no heli-deck and/or no lifeboat.

13. A method as claimed in any preceding claim, wherein the platform is an unmanned platform and requires personnel to be present for fewer than 10,000 maintenance hours per year.

14. A pressure protection system for a platform of an offshore oil and gas installation, wherein the platform is connected to a source of hydrocarbons via a pipeline, the pressure protection system comprising: a safe link device at the pipeline; wherein the safe link device is located subsea and outside of the safety zone of the platform; a subsea High Integrity Pressure Protection System (HIPPS) at the platform and/or the pipeline for protecting the platform; and wherein the safe link device is arranged to activate to release pressure from the pipeline when the pressure exceeds a preset threshold that is above the design pressure for the platform.

15. A pressure protection system as claimed in claim 14, wherein the HIPPS is arranged to control the pressure to a lower level than the preset threshold for activation of the safe link device.

16. A pressure protection system as claimed in claim 14 or 15, wherein the preset threshold is above the normal operating pressure for the platform and above the ultimate limit state pressure for the pipeline.

17. A pressure protection system as claimed in claim 14, 15 or 16, wherein the preset threshold is below maximum allowable accumulated pressure for the platforms and/or below the accidental limit state pressure for the pipeline.

18. A pressure protection system as claimed in any of claims 14 to 17, wherein the safe link device is a physically triggered device including at least one of: a structure in the pipeline that is designed to burst at a set pressure, a valve with a breakable pin that will fail at the required pressure, or a rupture disc.

19. A pressure protection system as claimed in any of claims 14 to 18, wherein the safe link device comprises a rupture disc that will break and release the pressure from the pipeline when the pipeline pressure exceeds the preset threshold.

20. A pressure protection system as claimed in any of claims 16 to 19, wherein the safe link device is located 500 m or more from the platform.

21. A pressure protection system as claimed in any of claims 16 to 20, comprising multiple safe link devices for redundancy and/or wherein the safe link device comprises multiple pressure activated mechanisms for redundancy.

22. A pressure protection system as claimed in any of claims 14 to 21, wherein the preset threshold is in the range 430-450 barg.

23. A pressure protection system as claimed in any of claims 14 to 22, wherein the platform has no mechanism for emergency depressurisation of a hydrocarbon inventory of the platform in the event of a fire or other emergency that causes an over-pressure.

23. A platform as claimed in any of claims 14 to 23, wherein the platform is an unmanned platform with no permanent personnel, wherein the unmanned platform has no provision of facilities for personnel to stay on the platform, for example there may be no shelters for personnel, no toilet facilities, no drinking water, no personnel operated communications equipment, no hell-deck and/or no lifeboat; and/or wherein the unmanned platform is arranged such that personnel are required to be present for fewer than 10,000 maintenance hours per year.

Description

[0033] Certain embodiments of the present invention will now be described in greater detail by way of example only and with reference to the accompanying drawings in which:

[0034] FIGS. 1 and 2 are schematic diagrams showing the layout of an offshore field development;

[0035] FIG. 3 is a perspective view of a 3D model of an example platform with a topside twisted 45 relative to the jacket; and

[0036] FIG. 4 is an elevation of another example platform when viewed from the north.

[0037] The following is described in the context of a possible field development 10. A 6-slots subsea production system (SPS) 12 is proposed at a first remote site, A. Approximately 12 km away, within a second remote site, B, is proposed an Unmanned Wellhead Platform (UWP) 14 and an Unmanned Processing Platform (UPP) 16.

[0038] The distance between remote site A and remote site B is approximately 12 km, while the distance from remote site B to the tie-in point at a host pipeline is approximately 34 km. A schematic illustration of the pipeline systems is shown in FIGS. 1 and 2. The water depth both at remote site A and remote site B and in the host area is in the range of 100 to 110 metres, and the seabed bathymetry is in general flat with no major features or pockmarks.

[0039] Oil, gas and water from the reservoir of remote site A are produced to the SPS 12. The well fluid is transported through an insulated and heat traced pipe-in-pipe pipeline 18 to remote site B. The UPP subsea and topside facility 16 at remote site B is protected from the high well shut-in pressure by a subsea high-integrity pressure protection system (HIPPS) system 20 as well as by a further HIPPS system that is on-board the UPP 16.

[0040] Oil, gas and water from the reservoir of remote site B are produced to the UWP 14. The UPP subsea and topside facility 16 is further protected from the high well shut-in pressure by a topside HIPPS system 22 on the UWP 14.

[0041] In order to ensure that the UPP 16 provides a high degree of safety in over-pressure situations, in particular for periods when personnel are on board for maintenance, then a safe link device 62 is used to provide enhanced pressure protection. The function of the safe link device 62 is to release the pressure from the pipeline 18 when it exceeds a set threshold defined based on a maximum permitted pressure at the platform. As shown in FIGS. 1 and 2 the safe link device 62 is located in the pipeline 18 prior to both of the UPP 16 and UWP 14 and outside of the safety zone for the two platforms 14, 16. For example the safe link device 62 may be 500 m or more away from the platforms 14, 16. Thus the safe link device 62 in this example acts to protect both platforms. It will be appreciated that the safe link device 62 could be located differently and may be placed to protect just the UPP 16, or just the UWP 14, or there may be separate safe link devices 62 for each platform 14, 16. The best implementation will depend on the features of a particular installation and the relative location of each platform and their safe zones.

[0042] The safe link device 62 is a structure in the pipeline 18 that will break or otherwise open to release the pressure from the pipeline 18 when it exceeds a set threshold defined based on a maximum permitted pressure at the platform. The pressure threshold within the pipeline 18 for activation of the safe link device 62 can be as discussed below. It should be appreciated that in general it is a local pressure differential that is needed to break the safe link device 62. Therefore, when designing the safe link device 6 the maximum permitted pressure for the pipeline needs to be considered with reference to the external pressure at the location of the safe link device 62, as well as also considering expected temperatures with reference to the material properties of the device 62. The expected pressure differential is what sets the design parameters for the safe link device 62.

[0043] The maximum permitted pressure at the platform in this context will be above the normal operating pressure for the UWP 14 and UPP 16 i.e., above the platform design pressure. This maximum pressure may also be above the ultimate limit state for the pipeline, but it could be lower than that in some circumstances. In general it would also be set to be above pressures that could be controlled and safely contained using the subsea HIPPS, UPP HIPPS and UWP HIPPS. It is typically below the maximum allowable accumulated pressure for the platform(s) and hence below pressures that would cause failure of the equipment on the platforms. It could also be below the accidental limit state pressure for the pipeline. Additionally, it may sometimes be set to be below pressures that would cause damage to the equipment without a failure of the equipment, so that the equipment on the platforms could be used again with minimal inspection and/or testing in situations where the safe link device 62 was triggered and the installation is later re-started. It will be understood that various designs could be applied to achieve the required functionality. The safe link device 62 is advantageously a physically triggered device, i.e. not reliant on sensors or actuators. This enhances the existing HIPPS since it means that the broader pressure protection system formed by the combination of the HIPPS and safe link device 62 uses two distinct mechanisms for release of pressure, one purely physical and one with sensors and electronic control. Thus, the safe link device 62 may be a structure in the pipeline that is designed to burst at a set pressure, such as a valve with a breakable pin that will fail at the required pressure, a rupture disc, or any other similar physical pressure relief mechanism that can be reliably designed to activate at the required pressure differential between the pipeline 18 and the external environment.

[0044] In this example the safe link device 62 comprises a rupture disc that is designed and calibrated based on the platform requirements and subsea conditions (e.g. temperature, pressure) in order to rupture at the threshold pressure. This rupture disc may generally be of similar design to known rupture discs that was used in topside installations. The safe link device 62 can be arranged so that the pipeline 18 vents to the environment when the safe link device 62 is triggered. Alternatively there may be systems in place to capture the contents of the pipeline 18 without hindering the pressure relief, such as a tank with a suitable arrangement of float valves to allow hydrocarbons to be captured to fill the tank as seawater exits the tank.

[0045] As noted above, the maximum pipeline pressure for activation of the safe link device 62 is set based on the pressure that can be permitted at the platform as well as on the subsea conditions at the location of the device 62. In the current example, where the safe link device 62 is used in combination with a subsea HIPPS, it is important to understand the difference between the Ultimate Limit State (ULS) condition and the Accidental Limit State (ALS) condition for a pipeline system with a HIPPS, and the additional safety contribution from the safe link device 62.

[0046] An example; based on the following assumed pressure parameters:

TABLE-US-00001 Wellhead shut-in pressure WHSIP = 700 barg(@subsea) Incidental Pressure with IP = 400 barg (defined by HIPPS HIPPS set points) Safe Link Failure Pressure SLFP = 430-450 barg

[0047] The WHSIP is the maximum pressure the pipeline system (i.e. pipeline and riser including attached components) can be exposed to, and without a High Integrity Pressure Protection System this is the pressure the pipeline system has to be designed for. The design is in general based on the incidental pressure, which is defined with an annual probability less than 10.sup.2 (100-year value), and the incidental pressure is used as input for verification of the Ultimate Limit State (ULS) condition. However, for the case with a HIPPS we have to verify an additional scenario, i.e. HIPPS failure. The HIPPS failure scenario should have low probability (defined by reliability requirements specified for the HIPPS), typically in the order of 10.sup.5-10.sup.4, and can be verified based as an accidental limit state (ALS) condition. Consequently, there is a difference in the design of a pipeline system with a HIPPS and without a HIPPS, as set out below:

[0048] Burst failure design without a HIPPS (fully rated pipeline system): [0049] IP=WHSIP=700 barg, and verified according to ULS condition.

[0050] Burst failure design with HIPPS: [0051] IP=400 barg, verified as ULS condition. [0052] SLFP=450 barg, verified as ALS condition

[0053] The use of a HIPPS will change the pressure probability density function for the pipeline, which then results in the differences in design criteria. With the above example including HIPPS then the safe link device 62 would be arranged to release the pipeline pressure if it reached 450 barg and in practice this might give a maximum permitted pipeline pressure in the range 430-450 barg as noted above. Thus, the breaking element of the safe link device 62, which could be a rupture disc as set out above, would be designed to break when the pressure reaches this range, taking account of the temperature and pressure conditions at the location of the safe link device 62.

[0054] The safe link device 62 will be located outside the platform safety zone. The safe link device 62 could include multiple parallel pressure relief systems such as by having multiple similar rupture discs. In this way there is redundancy in the design of the safe link device 62. For example, if one rupture disc is degraded or damaged then the safe link device 62 should still operate to release over-pressure via another of the multiple rupture discs. For similar reasons it might be decided to install multiple safe link devices 62.

[0055] Injection of water for pressure support is planned for the reservoirs of both remote site A and remote site B via respective water injection pipelines 24, 26.

[0056] Produced fluid from remote site A and remote site B is mixed upstream of a subsea separator 30. The subsea separator 30 is a three phase separator operating at approximately 40 bar initially. The temperature in the separator 30 is high (90 C.) and good separation is expected.

[0057] Oil and water leaving the separator 30 is metered by a multiphase flow meter 32 and exported to a host 34. The receiving pressure at the host 34 will be kept at the same pressure as the subsea separator 30 to avoid flashing and multiphase flow in the export pipeline or inlet heater at the host 34. The oil is only partly stabilized in the subsea separator 30, and further stabilization to pipeline export specification is assumed at the host 34.

[0058] The subsea separator 30 and pumps (not shown) are provided as a subsea separator and booster station (SSBS) 29, which is located as close to the UPP 16 as possible to minimize condensation and liquid traps in the gas piping from the separator 30 to the UPP 16.

[0059] An umbilical 50 connects the UPP 16 to the host 34. The umbilical provides remote control of the operations of the UPP 16, as well as of the operations of the SPS 12, UWP 14 and SSBS 29 via secondary umbilicals 52, 54, 56. The secondary umbilicals 52, 54, 56 also supply any required power and chemicals required from the UPP 16 to the SPS 12, UWP 14 and SSBS 29.

[0060] Gas at 40 bar is delivered from the separator 30 to the UPP 16 topside inlet cooler 36 through a dedicated riser 38. The inlet cooler 36 comprises a seawater-cooled shell and tube heat exchanger. TEG is injected into the gas for hydrate inhibition before cooling the gas to 20 C. in the seawater-cooled shell and tube inter stage cooler 36.

[0061] Condensed water and hydrocarbons are removed in a downstream scrubber 37. Liquid from the scrubber 37 flows by gravitation back down to the subsea separator 30 through a dedicated riser 40.

[0062] The gas from the scrubber 37 is then compressed to around 80 bar in a first stage compressor with a discharge temperature of around 80 C. The temperature should ideally be as low as possible to reduce the amount of glycol required for dehydration.

[0063] The maximum cricondenbar pressure of the export gas is 110 barg. The cricondenbar is the pressure below which no liquid will be formed regardless of temperature. The cricondenbar is a property of the gas. The cricondenbar is determined by the conditions in the inlet scrubber 37.

[0064] The pressure in the scrubber 37 is determined by the pressure in the subsea separator 30. A low pressure in the separator 30 will reduce the flash gas in the export oil and is at some point in time required to realize the production profiles. The required compression work and power consumption will however increase with a lower pressure. The separator 30 will operate at about 40 bar initially and the pressure will be reduced to 30 bar or even lower towards the end of the lifetime.

[0065] The selected UPP 16 design facilitates the unmanned processing of oil and gas in remote site B. A combination of subsea processing and topside processing on the UPP 16 can maximise operability and minimise capital and operational expenditure.

[0066] The UPP 16 has a steel jacket configuration. The jacket 46 is square with a spacing of 14 metres between the support columns 114. The jacket orientation is turned at 45 to the platform north to optimise weight versus size for the topside 48, so that the topside decks 48 are at 45 to the square of the jacket 46, as shown in FIG. 3. By way of example, a possible UPP layout is shown in elevation in FIG. 4, where the topside includes a spider deck 102, emergency shutdown valve (ESDV) deck 104, cellar deck 106, cellar mezzanine deck 108, process deck 110 and weather deck 112 respectively.

[0067] The UPP 16 uses a piled, four legged, symmetrically battered jacket 46 to support the topside 48. The topside 48 is 19.8 m19.8 m across the main structural span and its orientation is twisted compared to the jacket 46.

[0068] Umbilicals will be pulled into the platform 48 with a winch located on the weather deck 112 and a umbilical slot and reserved space are provided for this activity in centre of the platform 48. The slot and reserved space can be used for other purposes on the module deck areas once the pulling operation is completed.

[0069] The SSBS 29 is located on the seabed within the jacket 46. A subsea separator 30 is used instead of a topside solution on the UPP 16 because a topside solution would require an additional level on the UPP 16 due to the size and weight requirement.

[0070] The separator 30 is based on a symmetrical design with a central top inlet arrangement and top outlet arrangements at both ends combined with cyclones for gas polishing. Likewise oil and water outlets are at the bottom part inside and outside respective baffle-plates. Operation of the subsea separator 30 is performed using several distinct control loops.

[0071] The levels in the separator 30 are measured by a profiler level detector system. Water level control will adjust speed of the water injection pump and the level of oil will adjust speed of the export pump. The pressure in the subsea separator 30 is adjusted by the speed of the 1st stage compressor (suction pressure control). The control loops will be closed at the host 34 using fibre optic cables in umbilicals 50, 56.

[0072] The platform 14, 16 would be oriented based on the prevailing wind direction. For example, with the prevailing wind defined as north to south and west to east, the process equipment should be located on the east and southeast side of the platform to allow for good natural ventilation.

[0073] As noted above, the platform layout advantageously uses a twisted topside 48 as shown in FIG. 3, with the topside decks 102, 104, 106, 108, 110, 112 rotated at 45 to the jacket 46. In this case the topside decks 102, 104, 106, 108, 110, 112 can be oriented with the cardinal points so that the sides of the square decks 102, 104, 106, 108, 110, 112 face north, south, east and west, and the jacket 46 is rotated at 45 relative to this, so that the corners of the jacket 46 face north, south, east and west.

[0074] The spider deck 102 is located at an elevation of 20 m above sea level. The spider deck 102 will be provided with three personnel landings 122 located on the north corner of the jacket 46 when the Service Operation Vessel (SOV) is located on the north and east side of the UPP 16 and on the west corner of the jacket 46 when the SOV is located on the west side of the UPP 16. For the personnel landing 122 on the north corner a muster area is defined. The muster area can be located below the module and close to the north staircase to the decks above.

[0075] It is likely that the preferred side for a SOV is the east side of UPP 16 due to the prevailing wind direction. For this reason a laydown area 128 for material handling is located on this side. The laydown area 128 is 85 m. From the laydown area 128 stairs are provided up to ESDV deck 104. Between the personnel landings and the laydown area 128, access and escape routes are provided.

[0076] The hang off arrangement for pipeline and risers that need 3D or 5D bend will be located on the spider deck 102. In addition is it likely that the umbilical and power cables should be hanged off at this level and routed directly up to the termination panels.

[0077] The ESDV deck 104 is located 4 m above the spider deck 102. Piping that enters the UPP 16 from the subsea are routed inside the jacket structure 46. For piping with an ESD valve, the ESD valve shall be located on ESDV deck 104. The pipeline specification will be terminated at the ESD valve, Piping including ESD valve should be designed according to ASME design code B31.3 Process piping. ESD valves for the 16 gas export and the 16 process line from the subsea separator will be the largest valves on this deck 104, and the valves will most likely set the deck height pending the arrangement for material handling. Termination cabinets for the umbilical (TUTU) will be located on this deck 104, on the north and close to the Umbilical slot. Two seawater pumps including strainers and hydraulic skid will be located on the west side of this deck together with a stacking area for seawater lift pump.

[0078] A temporary and removable open drain tank is located on the ESDV laydown area 130. The laydown area 130 is sized (52.5 m) to allow for material handling when the drain tank is on the laydown area 130. The crane operator will have direct view and good accessibility with the weather deck crane 132.

[0079] The cellar deck 106 is located 6 m above the ESDV deck 104. Access to cellar deck 106 is through a stair case on the north side from both the process deck 110 above and the ESDV deck 104 below. The stair case is in connection with the cellar deck laydown area 130. The south stair from the above and below area will land close to the bridge. From a north laydown area to a bridge 136 on the south side is a main escape route connecting the staircases through the platform decks 102, 104, 106, 108, 110, 112. The bridge 136 is 75 m long and will tie the UPP 16 to the UWP 14.

[0080] The cellar deck mezzanine deck 108 is 4.6 m above the cellar deck 106 in this example. Access to the deck below and the deck above is arranged for by the north and south staircase, in addition to the internal south stair. A local instrument room with natural ventilation is on the south part of this mezzanine deck 108. Access can be provided from a stair on the south end or through the stair on the north east corner of the room.

[0081] Above the cellar deck 106 and cellar deck mezzanine 108 is a process deck 110. In this example the process deck 110 is located 9 m above the cellar deck 106. Access to the deck below is arranged for by the north and south staircase. Access to the weather deck 112 is arranged on the east and west side.

[0082] The weather deck 112 is 8 m above the process deck 110 in this example. From this deck the access and escape possibilities are through stairs case on the east and west side of the installation and down to the cellar deck 106. The main equipment on the weather deck 112 is an intercooler heat exchanger and inlet gas heat exchangers. Dual heat exchangers will be stacked on top of each other on the south west deck area. A package with chemical tanks and pump may be required pending the supply of chemicals from OFC through the umbilical.

[0083] The vent stack 142 is located on the south-east corner due to the prevailing wind direction and to be close to process equipment for shortest possible pipe routing. Relief valves for the vent line will be located close to the vent stack 142. In this example the size of the stack is 1.51.510 m. The vent stack 142 is used for cold venting during certain procedures, and it is not used for emergency depressurisation in the event of a fire or other emergency. The vent stack 142 can be used for pressure relief of methane gas through cold vent 142 during barrier testing and maintenance operations that require pressure relief. It will be appreciated that there is no flare for this platform 16, which is a significant difference to the conventional arrangement. In the event of a fire there is no emergency depressurisation at the platform and instead the piping and equipment on the platform 16 is isolated from wells and larger volumes of hydrocarbons in connected external piping by valves, then left at operating pressure. The pressure will be released by the safe link device 62 if it exceeds the burst pressure of the safe link device 62, and the HIPPS for the UPP 16 may also act to control the pressure under some circumstances. As discussed above this generates an added risk in relation to escalation of the fire, but this risk can be managed by restricting the size of the platform 16 and hence minimising the evacuation time, and also by adding passive fire protection as described below.

[0084] The platform crane 132 is located on the north east corner for good access to all the laydown areas 128, 130 provided on the various decks below. This has an 18 m reach and the access to the laydown areas 128, 130 as well as to the SOV is aided by the twisted topside arrangement of the platform 16.

[0085] Goods lifted by the SOV to the spider deck laydown area 128 can be picked up by the platform crane 132 and moved to a local laydown area 130. An area on the weather deck 112 can be reserved for helicopter drop, although it will be appreciated that the platform design does not allow for a hell-deck.

[0086] It will be appreciated that the exact layout for the platforms in terms of the decks that are present and the equipment that is used can vary. The layout of the installation can also vary. The invention is as defined by the claims and the above discussion is an example of one implementation of a safe link device 62.