NO340075B1

NO340075B1 - A MEG storage system and a method for storing MEG

Info

Publication number: NO340075B1
Application number: NO20150842A
Authority: NO
Inventors: Gudmund Roger Totland; Jan-Otto Reimers; Tom Grimseth
Original assignee: Kongsberg Oil & Gas Tech As
Priority date: 2015-06-26
Filing date: 2015-06-26
Publication date: 2017-03-06
Also published as: WO2016207359A3; NO20150842A1; WO2016207359A2

Description

The present invention regards subsea storage of chemicals such as hydrate inhibitor Mono Ethylene Glycol (MEG). The invention regards in particular a MEG storage system comprising a buffer tank arranged at a seabed for storage of MEG and a plurality of conduits for providing the flow of MEG to and from the surface. The invention also regards to a method for storage and control of the MEG in the system.

Production of oil and gas from subsea production facilities tied back to a platform requires use of a number of chemicals. Some chemicals are consumed in very small quantities (often referred to as ppm chemicals), but some types are needed in large quantities. Methanol and glycol based inhibitors such as mono ethylene glycol (MEG), di-ethylene glycol (DEG) and tri-ethylene glycol (TEG) are typical examples of large volume chemicals. Natural gas pipelines deep below sea level are subject to such conditions as lo w temperatures and high pressure, a combination prone to formation of hydrates. To ensure efficient transport through the pipelines, a hydrate inhibitor such as MEG is, among other things, added to the natural gas. Especially subsea production of gas requires injection into the flow line of significant volumes of MEG to prevent freezing and formation of hydrates at low temperatures and high pressures. In oil production systems MEG or other glycol based inhibitors and lor methanol are used for hydrate inhibition on cold start conditions, when depressurizing and pressure testing of safety barriers.

MEG used for hydrate inhibition of unprocessed gas in flow lines is often regenerated and reused. Some MEG will be lost in the process and has to be replaced. Thus, it is common to find on a production platform receiving unprocessed oil and gas from subsea producers, at least two MEG tanks, one lean MEG tank (unused MEG or regenerated MEG) and one rich MEG tank (MEG from the process due for entry into the regeneration plant).

It is customary to keep storage of MEG on one of the platform decks or in the hull of some type of floaters. For some floating production platforms, weight and space are constraints with respect to further field development, as many platforms end up with more tie-backs than originally planned. There is an increased need for hydrate inhibitor as the production increases. Also the changes in the composition of the well streams may increase the required amount of available hydrate inhibitor. Without enough hydrate inhibitor available production must be reduced or stopped.

There is therefore for some platforms a potential advantage in moving tanks for storage of MEG to the seabed where there is space and weight carrying capacity in abundance. However, production regularity is closely bound to availability at all times of said chemicals, thus creating issues over the concept of locating volume chemicals on the seabed and the potential reduction in production system availability.

Today, there exists several apparatus, systems and methods by which one can safely and effectively store fluids in undersea environments. The common method is to store the liquid in tanks arranged on the seabed. Different methods are also described in prior art for separating different fluids in a storage tank.

Publication WO 02/42182 Al, describes a method for separating two fluids in a storage tank. The method concerns a method for separating two fluids in a tank by interposition of a psuedo membrane between the two fluids. The method comprises the step of; making a stable emulsion from at least two immiscible liquids; placing said emulsion at the interface between the two fluids so as to constitute said membrane. The invention also concerns a tank comprising a separating membrane. The publication also describes, in an embodiment, the storage of water combined with a higher density fluid. The water with lower density is arranged on top with a pseudo membrane between the water and the higher density fluid. A filling line of the higher density fluid is located in the bottom of the tank, while a filling line of water is arranged on top of the tank.

Publication GB 1122975 Bl, describes a method and apparatus for the storage of petroleum under water, employing hydraulic displacement principles. The hydraulic displacement storage apparatus contains varying quantities of petroleum and displacement water, separated by a membrane. The displacement water is located at the bottom of the tank and has a filling line arranged at the same end. A pump is arranged for filling of water and control the pressure inside the tank for discharging of petroleum.

Publication NL 8002206 A, describes an underwater oil storage tank. The tank, which is wholly or partly placed underwater, is subdivided into an upper and a lower compartment and separated by a flexible foil material. The upper compartment holds the oil whilst the lower compartment is filled with water. During discharge of oil, the lower compartment is filled with water, and vice versa, so that the liquid level in the tank remains approximately constant and external forces on the tank remain balanced by the contents.

Publication US 3568865 A, discloses a pressure vessel for discharging of liquid from a container by using fluid (air) pressure. The system has a buffer tank.

Publication US 5568885 A, discloses another liquid dispensing system, comprising a liquid container where fluid (air) pressure is used to discharge liquid from the container. The system comprises a controller that selectively manipulates a valve to direct flow through the dispensing system. Both publications US 356 8865 A and US 556 8885A, discloses a system where a top section of the container is arranged for holding a control fluid (air) that displays a density less than the density of liquid that are discharged.

The prior art publications does not disclose a system or method for subsea storage of hydrate inhibitor such as MEG. There exist several differences using the MEG as the stored fluid, compared to traditional storage of oil/petroleum in combination with seawater. MEG has a typical density of 1113 kg/m3 at 20 degrees C and atmospheric conditions as compared to the specific gravity of seawater at typically 1025-1030 kg/m3 depending on temperature and salinity. MEG has therefore a higher density than seawater, making the MEG to be positioned at the bottom section of a storage tank. This requires increased tank pressure in order to extract the MEG form the bottom of the tank. In addition, prior art does not teach of a system that contains a buffer storage located subsea coordinating with a topside storage tank, and wherein the buffer storage is arranged to refill or extract the MEG volumes in the topside storage tank.

The invention addresses a system organized to provide seabed based storage of MEG without compromising on availability and thus on production regularity, further the subsea storage system has the potential to increase the amount of available MEG and reduce risk for production stops due to lack of MEG.

One objective is to use only such components as already have been extensively employed in subsea production systems and are of proven reliability in operation. This approach alleviates the need for research and qualification programs with all their inherent potential costs and/or problems. Combined with good maintainability of key components and redundancy schemes the regularity will not be reduced. To the contrary it may even be improved by allowing more MEG available as a buffer.

An object of the invention is to provide seabed based storage of MEG without compromising on availability and thus on production regularity.

Another object of the invention is to free up space on the platform.

Another object of the invention is to increase the amount of available MEG and reduce risk for production stops due to lack of MEG.

Another object of the invention is to build a MEG storage system by using common components that have been extensively employed in subsea production systems and are of proven reliability in operation.

Yet another object of the invention is to have a compact riser solution and only require one or a few riser slots at the platform.

The intention according to the invention is also based on the economical aspect, by building a redundancy for the supply of MEG and avoiding the risk of production stops.

In the following the term "MEG" is used for and includes chemicals such as methanol and glycol based inhibitors such as mono ethylene glycol (MEG), di-ethylene glycol (DEG) and tri-ethylene glycol (TEG), or any hydrate inhibitor which has physical properties compatible with storage by the techniques described in this document.

The term "topside" is in the following used for a structure or an apparatus or the part of a structure or an apparatus that is located above sea level or floating at sea level.

The term "subsea" is in the following referred to a structure or an apparatus being under water or below the sea level.

The present invention relates to a MEG storage system. The system comprises;

a topside intermediate feed tank;

at least one subsea pressure retaining tank comprising a bottom section for holding MEG and a top section for holding a control fluid for controlling the fluid level of the MEG in the at least one subsea pressure retaining tank, which control fluid displays a density which is less than the density of MEG;

at least one first conduit providing a fluid conduit path between the top section of the at least one subsea pressure retaining tank, and a topside pressure controlling means for controlling the pressure of the control fluid in the at least one subsea pressure retaining tank; and

at least one second conduit providing a fluid conduit path between the topside intermediate feed tank and the bottom section of the at least one subsea pressure retaining tank.

The at least one subsea pressure retaining tank, is arranged at the seabed, comprising a bottom section for holding the MEG fluid, and a top section for holding a control fluid. The control fluid displays a density which is less than the density of MEG. Suitable control fluid is freshwater, seawater, purge gas, etc, any fluid with a density less than the density of MEG. Purge gas can be natural gas (e.g. sales quality), or Nitrogen N2, depending on platform specifics. In a preferred embodiment of the present invention, the control fluid is seawater. The seawater being free and easily accessible and displays a density which is less than the density of MEG.

Further, the MEG and the control fluid are stored inside the at least one subsea pressure retaining tank separated by a flexible membrane. The membrane is a physical membrane made from rubber, plastic, textiles, fibers or other flexible fabric and any combinations thereof. In one embodiment the edge or the outer circumference of the membrane is attached to the inner wall along an inner circumference of the at least one pressure retaining tank, giving a tight sealing between the two separated fluids. Further, the membrane is flexible and has a tensile surface (when the membrane is stretched) allowing for either one of the fluids to cover substantially the volume of the at least one subsea pressure retaining tank. The flexible membrane being able to depress the MEG located at the bottom section of the tank, in order to extract the MEG from the tank. In one embodiment according to the invention the edge of the membrane is attached to the top section of the at least one subsea pressure retaining tank, giving more space to the MEG to be stored. A person skilled in the art would know in fact that depending on the size of the tank and the amount of MEG to be stored, the position and the attachment point of the membrane can vary.

According to the invention, at least one first conduit comprises a fluid conduit path between the top section of the at least one subsea pressure retaining tank and a topside pressure controlling means for controlling the pressure of the control fluid in the at least one subsea pressure retaining tank. The at least one second conduit comprises a fluid conduit path between the topside intermediate feed tank and the bottom section of the at least one subsea pressure retaining tank. Preferably, the conduit is a riser conduit for filling and discharge of MEG.

MEG fluid has only a little higher density than seawater. In some cases there will be a need to increase the pressure in the at least one second riser conduit, in order to fill MEG from the topside intermediate feed tank to the at least one seabed pressure retaining tank. It may be advantageous to arrange a topside pump for pressurizing MEG drawn form the topside intermediate feed tank and discharging it into the at least one second riser conduit for transfer of MEG from the topside intermediate feed tank to the at least one subsea pressure retaining tank.

In a preferred embodiment according to the invention, the MEG storage system comprises a topside intermediate feed tank and at least one subsea pressure retaining tank for the buffer storage. The topside intermediate feed tank being placed on a floating unit, a floating structure or a platform. The at least one subsea pressure retaining tank, which is a seabed storage facility, is designed to be constantly fluid filled and thereby withstand ambient pressure at the intended subsea level. Additionally the at least one subsea pressure retaining tank is designed to withstand a predetermined internal overpressure. The predetermined pressure for the subsea pressure retaining tank is a pressure in the range from 5 barg to 15 barg over the surrounding sea. The term barg is the pressure reading relative to current atmospheric pressure. The deeper the storage is arranged, the higher pressure is required for the pressure to be sufficient to force the MEG up into the topside intermediate feed tank. For installation on 100 meters depth the pressure can be typically 1-5 barg, at 1000 meters depth the pressure can be from 10-20 barg.

At the interface of the two fluids, an elastic membrane is arranged for separating the MEG from the seawater. The seawater of the at least one subsea pressure retaining tank is connected to the topside by means of a first riser conduit arranged with a pressure controlling means in order to fill or extract seawater. In case of a need for building up pressure inside the at least one subsea pressure retaining tank, seawater will be filled into the top section of the at least one subsea pressure retaining tank. Opposite, by extracting seawater the pressure will be decreased.

The MEG is at one end in fluid communication with the bottom section of the at least one subsea pressure retaining tank, and the opposite end with the topside intermediate feed tank by means of at least one second riser conduit for filling and discharging of MEG. Advantageously, a topside pump is arranged for controlling the pressure of the MEG in the at least one second riser conduit.

A pressure controlling means in form of a purge pump is located topside and arranged to pump seawater through the at least one first riser conduit and into the top section of the at least one subsea pressure retaining tank. The pressurized seawater entering the top section and pushing the elastic membrane towards the MEG in the bottom section, in order to extract and lift the MEG from the at least one subsea pressure retaining tank to the topside intermediate feed tank.

As mentioned, the pressure controlling means is advantageously a purge pump arranged topside on a floating unit, a structure or a platform. The pump is arranged to pump seawater into the at least one first riser conduit. The benefit for arranging a pump topside is that it is easy to install, easy replaceable and allows easy access for maintenance. The at least one first riser conduit is a seawater intake/outlet. The predetermined pressure in the at least one pressure retaining tank and the pressure controlling means displays enough pressure to lift the MEG from the at least one subsea pressure retaining tank to the topside intermediate feed tank. This system avoids the many drawbacks of installing a subsea pump for pumping of the MEG fluid.

The topside intermediate feed tank is a tank for storage of MEG fluid ready for use. The tank receives MEG in batches from the at least one subsea pressure retaining tank on a need to basis. From the topside intermediate feed tank the MEG is piped to the MEG booster pumps for transmission to the subsea production site in the normal way. This beneficial system still uses MEG tank arranged topside, but this tank is now reduced in size to a small fraction of the size required if all the MEG were to be stored topsides. For some cases, this may save up to 1500 tons of weight (steel plus MEG volume).

The at least one subsea pressure retaining tank, will typically have buffer functions, i.e. the steady state flow of MEG is essentially in balance between the lean tank, process, regeneration plant and rich MEG tanks, all of which are located topsides. The buffer volumes subsea is required to fill up the MEG volumes lost regularly in the process and provide the supply of MEG in case of process anomalies, such as downtime of the regeneration plant. According to the invention the rich MEG tank can also be a buffer type and placed subsea in order to store bigger amount of rich MEG.

In a preferred embodiment according to the invention, the topside intermediate feed tank is communicating with the pressure controlling means. Preferably the pressure controlling means is a purge pump located topside and arranged to pump the seawater through the at least one first riser conduit and into the seawater at the top section of the at least one pressure retaining tank. The topside intermediate tank is designed with a predetermined amount/volume of MEG stored inside the tank. In case when the volume is less than the predetermined volume, the pump will start to pump seawater into the at least one subsea pressure retaining tank, in order to lift the additional MEG needed from the at least one subsea pressure retaining tank to the topside intermediate feed tank. In the other case when the volume of MEG inside the topside intermediate feed tank is bigger than the predetermined volume, the pump will extract seawater or allow seawater to flow out from the at least one pressure retaining tank, giving a reverse flow of MEG from the topside intermediate feed tank and into the at least one subsea pressure retaining tank. In some cases the reverse flow of MEG does not depend on the pump to be active. By opening the pump/valve the MEG will automatically have a reverse flow. This last method is also applicable when filling of MEG from the topside intermediate feed tank, to the at least one seabed pressure retaining tank. Further, it may also be advantageous to arrange a topside pump for controlling the pressure of MEG in the at least one second conduit, in order to obtain sufficient pressure for transfer of MEG from the topside intermediate feed tank to the at least one subsea pressure retaining tank.

The riser is also of particular interest. The subject invention would typically be of interest to floating production platforms using flexible risers for tie-back of production wells. Flexible risers are invariably significant cost items. A riser slot is a valuable asset. It is imperative that riser functionality is kept to a minimum and that the functionality required can be supplied by a single riser. Riser slots can also be a limitation on platforms and the present invention will have a compact riser solution and will only require one or a few riser slots.

Transport of MEG and control fluid between topside and subsea is slow and does not need to reflect the high rates associated with discharge of supply ships MEG volumes. Typical flow rates required could equate to 2 x 1-2 inches diameter conduits. Such a riser could be achieved by means of a large number of tubes, typically up to 19 mm ID super duplex material (for a 300 meters water depth dynamic umbilical), configured in the same style as control/service dynamic umbilical's. This could entail two manifolds each end of the riser to comingle parallel flows in the tubes for MEG and control fluid respectively. The rich MEG tank is also of the buffer type and only required to pass MEG and control fluid at slow rates compatible with small-bore conduits. The riser requirements for both lean MEG and rich MEG tanks can clearly be satisfied by means of a single riser, including any control and instrumentation requirements.

An acoustic sensor is arranged at the top of the subsea pressure retaining tank in order to detect the MEG level in the tank. In addition, a content sensor can also be arranged at the second riser conduit to measure the % water in MEG content.

The inherent nature of a dynamic umbilical riser is to contain a multitude of small bore tubes for mechanical flexibility. Rather than manifolding of such small bore tubes into a functionally single conduit by interconnecting many tubes at both ends, it may be beneficial to connect individual conduits to separate tanks, thus providing a system robust against single failures. It would mean that by a fault in one tank, the other tanks still in god condition, can continue operation without the cost and time delays of a subsea intervention.

In another preferred embodiment of the present invention, the MEG storage system comprises four subsea pressure retaining tanks located on the same base structure and sharing foundation. A purge pump is arranged to control the pressure and flow of seawater in the at least one first riser conduits. Each individual subsea pressure retaining tank is arranged with an individual first riser conduit and a second riser conduit according to the invention, giving a redundant system. By a fault in one individual subsea pressure retaining tank, the other tanks still in god condition, can continue operation without the cost and time delays of a subsea intervention. This system with a plurality of subsea pressure retaining tanks is also beneficial in case of maintenance and repair, and also by means of modularization. The last is referred to the simple operation when adding or removing individual tanks.

A person skilled in the art would know in fact that the at least first riser conduit and the at least one second riser conduit can be arranged with required val ves and stab connectors. The valves can be intervention valves in order to remove or isolate a tank without disturbing the others; they are ROV operated and affects the system design in minimal extent. This is subsea standard and will be recognized by everyone in the industry as it is, namely RFO (ready for operation, ie commissioning) or maintenance valves.

Also according to the invention, an Umbilical Termination Assembly (UTA) is arranged to the system. The UTA is an interface between the umbilical and the jumpers connecting the pressure tanks. The UTA and its use and purpose are known to the person skilled in the art.

The invention also discloses a method for operating a MEG storage system. The method of operating a MEG storage system comprising: a topside intermediate feed tank ;

at least one first conduit providing a fluid conduit path between the top section of the at least one subsea pressure retaining tank and a topside pressure controlling means for controlling the pressure of the control fluid in the at least one subsea pressure retaining tank; and

at least one second conduit providing a fluid conduit path between the topside intermediate feed tank and the bottom section of the at least one subsea pressure retaining tank; which method comprises the step of; - bringing MEG to flow from the at least one subsea pressure retaining tank to the topside intermediate feed tank via the at least one second conduit by bringing the pressure controlling means to increase the pressure of the control fluid in the at least one subsea pressure retaining tank; and - bringing MEG to flow from the topside intermediate feed tank to the at least one subsea pressure retaining tank via the at least one second conduit by bringing the pressure controlling means to decrease the pressure of the control fluid in the at least one subsea pressure retaining tank.

According to the present invention, wherein the intermediate feed tank is in communication with the pressure controlling means in order to control and regulate the amount of MEG in the topside intermediate feed tank, which method further comprises the steps of: -when the level of MEG in the topside intermediate feed tank is below a predetermined level, bringing the pressure controlling means to increase the pressure of the control fluid in the at least one subsea pressure retaining tank in order to lift the MEG from the at least one pressure retaining tank to the topside intermediate feed tank; -when the level of MEG in the topside intermediate feed tank is above a predetermined level, bringing the pressure controlling means to decrease the pressure of the control fluid in the at least one subsea pressure retaining tank in order to move the MEG from the topside intermediate feed tank to the at least one pressure retaining tank.

According to the invention, it may also be advantageous to arrange a topside pump for controlling the pressure of the MEG in the at least one second conduit. By pressurizing the MEG fluid drawn from the topside intermediate feed tank and discharge it into the at least one second conduit for transfer of MEG from the topside intermediate feed tank to the at least one subsea pressure retaining tank.

In an embodiment of the invention, the at least one subsea storage tank comprises a flexible membrane separating the bottom section from the top section of the subsea pressure retaining tank. The control fluid is preferably seawater and the pressure controlling means is preferably a purge pump. Further, the at least one subsea pressure retaining tank is designed to withstand an internal pressure in the range from 1 barg to 20 barg. In an advantageous method the MEG storage system comprises of four individual subsea pressure retaining tanks, each with individual first and second riser conduits. Fig. 1 shows an embodiment of the present invention where the subsea pressure retaining tank is arranged with a membrane separating MEG and seawater. Fig. 2 shows a schematic diagram of the MEG storage system with four subsea pressure retaining tanks.

Various objects, features, aspects and advantages of the inventive subject matter will become more apparent from the following detailed description of preferred embodiments, along with the accompanying drawings figures in which like numerals represent like components

Figure 1 shows an embodiment of a MEG storage system, according to the present invention. The system comprises a topside pump 5 arranged to control pressure and flow of a control fluid 3. The control fluid 3 is preferably seawater. Seawater 3 is led through a first riser conduit 9 to a subsea pressure retaining tank 1. The first riser conduit 9 has an intake/outlet connection 20 for intake and extraction of seawater 3.

As shown in Fig. 1, the subsea pressure retaining tank 1 is arranged at the seabed for storage of MEG 2. The subsea pressure retaining tank 1 comprises a flexible membrane 12 arranged internally for separating the MEG 2 from the seawater 3. The content of the pressure tank 1 can be divided into a top section with seawater, a flexible membrane 12 separating the two fluids, and a bottom section 2 with MEG 2.

The subsea pressure retaining tank 1, which is a seabed storage facility, is designed to be constantly fluid filled and thereby withstand ambient pressure at the intended subsea level. Additionally the subsea pressure retaining tank 1 is designed to withstand a predetermined overpressure on the inside tank 1. The predetermined pressure for the subsea pressure retaining tank 1 is a pressure in the range from 1 barg to 20 barg over the surrounding sea, depending on the depth. The deeper the storage is arranged, the higher pressure is required for the pressure to be sufficient to force the MEG 2 up into the topside intermediate feed tank 11.

The top section of the subsea pressure retaining tank 1 containing seawater 3, is connected by means of a first riser conduit 9 to a topside purge pump 5. The

MEG 2 at the bottom section of the subsea pressure retaining tank 1 is connected to a topside intermediate feed tank 11 by means of a second riser conduit 10 for filling and discharging of MEG. The purge pump 5 located topside is arranged to pump the seawater 3 into the pressure retaining tank 1. The pressurized seawater 3 is entering the top section and pushing the elastic membrane 12 towards the MEG 2 in the bottom section, in order to extract and lift the MEG 2 from the subsea pressure retaining tank 1 to the topside intermediate feed tank 11. An acoustic sensor 13 is arranged at the top of the pressure retaining tank 1 in order to detect the MEG 2 level in the tank 1.

A content sensor 14 is also arranged to measure the water 3 in MEG 2 content. The Fig. 1 also shows the first riser conduit 9 and the second riser conduit 10 is connected each to a connection point 7, 8 for respectively seawater line and MEG 2 line. A level control 22 is arranged at the topside intermediate feed tank 11 in order to control and measure the desired level of MEG 2 in the tank. An inlet pipe 21 is arranged for the external supply of MEG 2, accordingly a feed line 15 is also located in the intermediate feed tank 15 for the MEG 2 injection system.

Figure 2 shows the MEG storage system with four subsea pressure retaining tanks 1. The system comprises four individually pressure retaining tanks 1, each individually connected to a first riser conduit 9 and a second riser conduit 10, thus providing a system robust against single failures. This means that by a fault in one subsea pressure retaining tank 1, the other tanks 1 still in god condition, can continue operation without the cost and time delays of a subsea intervention. A purge pump 5 is arranged to control the pressure and flow of seawater 3 in the at least one first riser conduit 9. A topside pump (not shown) can also be arranged for controlling the pressure of the MEG 2 in the at least one second riser conduit 10.

The at least one second riser conduit 10 is connected to the bottom section of each individual subsea pressure retaining tank 1, providing individual MEG fluid conduit paths to the topside intermediate feed tank 11. The at least first riser conduit 9 and the at least one second riser 10 conduit can be arranged with required valves and stab connectors as shown in figure 2. The valves can be intervention valves in order to remove or isolate a tank without disturbing the others; they are ROV operated and affect the system design in minimal extent. Also seen in figure 2, an Umbilical Termination Assembly (UTA) is arranged to the system. The UTA is an interface facility for connection of umbilical conduits to the jumpers.

The figures shows the following reference number;

Claims

1. A MEG storage system, wherein the system comprises; a topside intermediate feed tank (11); at least one subsea pressure retaining tank (1) comprising a bottom section for holding MEG (2) and a top section for holding a control fluid (3) for controlling the fluid level of the MEG (2) in the at least one subsea pressure retaining tank (1), which control fluid (3) displays a density which is less than the density of MEG (2); at least one first conduit (9) providing a fluid conduit path between the top section of the at least one subsea pressure retaining tank (1) and a topside pressure controlling means (5) for controlling the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1); and at least one second conduit (10) providing a fluid conduit path between the topside intermediate feed tank (11) and the bottom section of the at least one subsea pressure retaining tank(l).

2. A storage system according to claim 1, wherein the at least one subsea pressure retaining tank (1) comprises a membrane (12) separating the bottom section from the top section.

3. A storage system according to claim 1 or 2, wherein the membrane (12) is a flexible membrane (12).

4. A storage system according to any one of claims 1-3, wherein the at least one second conduit (10) is arranged for filling and discharging the MEG (2) and the at least one first conduit (9) is arranged for filling and discharging the control fluid (3).

5. A storage system according to any one of claims 1-4, wherein the topside intermediate feed tank (11) is in communication with the pressure controlling means (5) in order to control and regulate the amount of MEG in the topside intermediate feed tank (11).

6. A storage system according to any one of claims 1-5, wherein a topside pump is arranged for controlling the pressure of the MEG (2) in the at least one second conduit (10).

7. A storage system according to any one of claims 1-6, wherein the pressure controlling means (5) is a purge pump arranged for controlling the pressure of the control fluid in the at least one first conduit (9).

8. A storage system according to any one of claims 1-7, wherein the at least one subsea pressure retaining tank (1) is designed to withstand an internal pressure in the range from 1 barg to 20 barg.

9. A storage system according to any one of claims 1-8, wherein the control fluid (3) is seawater.

10. A storage system according to any one of claims 1-8, wherein the control fluid (3) is a gas.

11. A storage system according to any one of claims 1-10, wherein the at least one first conduit (9) and the at least one second conduit (10) is arranged with at least one of a valve or a stab connector.

12. A storage system according to any one of claims 1-11, wherein a sensor (14) is arranged to measure the water content in the MEG (2) fluid.

13. A storage system according to any one of claims 1-12, wherein an acoustic sensor (13) is arranged to detect the MEG (2) level in the at least one subsea pressure retaining tank (1).

14. A method of operating a MEG storage system comprising: a topside intermediate feed tank (11); at least one subsea pressure retaining tank (1) comprising a bottom section for holding MEG (2) and a top section for holding a control fluid (3) for controlling the fluid level of the MEG (2) in the at least one subsea pressure retaining tank (1), which control fluid (3) displays a density which is less than the density of MEG (2); at least one first conduit (9) providing a fluid conduit path between the top section of the at least one subsea pressure retaining tank (1) and a topside pressure controlling means (5) for controlling the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1); and at least one second conduit (10) providing a fluid conduit path between the topside intermediate feed tank (11) and the bottom section of the at least one subsea pressure retaining tank (1); which method comprises the steps of: - bringing MEG (2) to flow from the at least one subsea pressure retaining tank (1) to the topside intermediate feed tank (11) via the at least one second conduit (10) by bringing the pressure controlling means (5) to increase the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1); and - bringing MEG (2) to flow from the topside intermediate feed tank (11) to the at least one subsea pressure retaining tank (1) via the at least one second conduit (10) by bringing the pressure controlling means (5) to decrease the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1).

15. The method according to claim 14, wherein the intermediate feed tank (11) is in communication with the pressure controlling means (5) in order to control and regulate the amount of MEG (2) in the topside intermediate feed tank (11), which method comprises the steps of: -when the level of MEG (2) in the topside intermediate feed tank (11) is below a predetermined level, bringing the pressure controlling means (5) to increase the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1) in order to lift the MEG (2) from the at least one pressure retaining tank (1) to the topside intermediate feed tank (11); -when the level of MEG (2) in the topside intermediate feed tank (11) is above a predetermined level, bringing the pressure controlling means (5) to decrease the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1) in order to move the MEG (2) from the topside intermediate feed tank (11) to the at least one pressure retaining tank (1).

16. The method according to claim 14 or 15, wherein a topside pump is arranged for controlling the pressure of the MEG (2) in the at least one second conduit (10) by pressurizing the MEG (2) drawn from the topside intermediate feed tank (11) and discharging it into the at least one second conduit (10) for transfer of MEG (2) from the topside intermediate feed tank (11) to the at least one subsea pressure retaining tank (1).

17. The method according to any one of claims 14-16, wherein the at least one subsea pressure retaining tank (1) comprises a membrane (12) separating the bottom section from the top section.

18. The method according to any one of claims 14-17, wherein the control fluid (3) is seawater.

19. The method according to any one of claims 14-18, wherein the pressure controlling means (5) is a purge pump for controlling the pressure of the control fluid (3) in the at least one subsea pressure retaining tank (1).

20. The method according to any one of claims 14-19, wherein the at least one subsea pressure retaining tank (1) is designed to withstand an internal pressure in the range from 1 barg to 20 barg.