WO2021029774A1

WO2021029774A1 - Pipeline pig method and apparatus

Info

Publication number: WO2021029774A1
Application number: PCT/NO2020/050202
Authority: WO
Inventors: Håvard EIDSMOEN; Ragnar STOKKE
Original assignee: Equinor Energy As
Priority date: 2019-08-12
Filing date: 2020-08-11
Publication date: 2021-02-18
Also published as: GB201911509D0; GB2586236A; GB2586236B

Abstract

An apparatus (5) and method for receiving a pipeline pig, the apparatus comprising a pig cleaning chamber (6) for cleaning a pig received from a pipeline connected to the pig cleaning chamber (6) and a pig storing cassette (26) for accommodating at least one pig received from the pig cleaning chamber.

Description

PIPELINE PIG METHOD AND APPARATUS

FIELD OF THE INVENTION

The present invention relates to wax and hydrate management in pipelines, and in particular, to wax and hydrate management in subsea hydrocarbon pipelines.

BACKGROUND

A problem in subsea oil and gas fields is the presence of natural gas hydrates and wax in pipelines and equipment. Typically, production fluids exit a wellhead at a temperature between 40°C and 150°C, whereas the surrounding seawater is between - 2°C and 15°C. As a result, the production fluids naturally cool as they are transported along a subsea pipeline. At some point in the pipeline, the temperature of the flowing production fluids (typically a mixture of oil, gas, and water) will reach the Wax Appearance Temperature (WAT) at around 20°C to 40°C. With further cooling, the fluid reaches the hydrate formation temperature, typically in the range 10°C to 20°C. As a result, wax and/or hydrate depositions can build up on the pipeline walls, and in the worst case, lead to complete plugging of the system.

Conventional approaches for inhibiting hydrate formation involve adding chemical inhibitors (e.g., methanol, glycol) to the well stream. However, these techniques are typically environmentally unfavourable due to the use of chemicals, and typically have little effect in inhibiting wax formation. Other solutions include heating and/or insulating the entire pipeline. However, this can be expensive and require a large energy source - especially for deep-sea pipelines.

"Cold-flow" solutions exist which do not require a heat source. In some examples, at the wellhead, the production fluids are actively cooled to allow or encourage solids (hydrates and/or wax) to form. The idea is to convert most of the gas phase into hydrates and transfer it in the form of hydrate-slurry in the pipeline. These deposits are then carried as small solid particles by the fluid as a slurry. While cold-flow delivery of well stream has the benefit of avoiding the cost of pipeline insulation and heating, typically wax and hydrate deposition is not avoided completely, or may be most problematic in a portion of the pipeline proximate to the well. Therefore, cold-flow pipelines may need to be periodically 'pigged' to ensure the line is running smoothly. ‘Pigging’ refers to the practice of using devices known as pigs to perform various maintenance or cleaning operations on a pipeline. The pig is typically a device, which is cylindrical or spherical in shape, and is forced along the pipeline by the production fluid flow. A cleaning pig is typically provided with bristles provided around the periphery to sweep the pipeline, abrasively scraping the sides of the pipeline and pushing debris ahead as the pig travels.

In conventional pigging systems, the pig is caught at an onshore receiver. Therefore, in the context of far offshore developments (where pipelines may extend to distances hundreds of kilometres offshore), the problem arises that pigging over such a distance may be time-consuming and impractical, due to maximum pigging speeds of typically 1 to 2 m/s.

SUMMARY

According to a first aspect of the invention, there is provided an apparatus for receiving a pipeline pig, comprising a pig cleaning chamber for cleaning a pig received from a pipeline connected to the pig cleaning chamber and a pig storing cassette for accommodating at least one pig received from the pig cleaning chamber.

In some embodiments, the pig storing cassette accommodates a plurality of pigs.

In some embodiments, the chamber has at least one inlet and at least one outlet for a cleaning fluid. Optionally, the cleaning fluid comprises methanol or Mono-Ethylene Glycol (MEG).

In some embodiments, the apparatus further comprises a heater coupled to the pig cleaning chamber.

In some embodiments, the pig storing cassette is detachable from the pig cleaning chamber.

In some embodiments, the pipeline connected to the pig cleaning chamber is a subsea hydrocarbon pipeline. According to a second aspect of the invention, there is provided a method for receiving a pipeline pig, comprising: receiving a pig in a pig cleaning chamber from a pipeline connected to the pig cleaning chamber; cleaning the pig; and receiving the pig from the pig cleaning chamber in a pig storing cassette for accommodating at least one pig. In some embodiments, the pig storing cassette accommodates a plurality of pigs.

In some embodiments, cleaning the pig comprises flushing the pig cleaning chamber with a cleaning fluid. Optionally, the cleaning fluid comprises methanol or Mono- Ethylene Glycol (MEG).

In some embodiments, before receiving the pig from the pig cleaning chamber in the pig storing cassette, the method according to the second aspect further comprises heating the pig cleaning chamber.

In some embodiments, the method further comprises detaching the pig storing cassette and replacing the pig storing cassette with an empty cassette.

In some embodiments, the pipeline connected to the pig cleaning chamber is a subsea hydrocarbon pipeline.

According to a third aspect of the invention, there is provided a pipeline system comprising at least one in-field pipeline, wherein the downstream end of the at least one in-field pipeline is provided with the apparatus according to the first aspect of the invention.

According to a fourth aspect of the invention, there is provided a method for wax management in a hydrocarbon pipeline system, comprising: pigging a first in-field pipeline; and while the first in-field pipeline is pigged, increasing the production rate of at least one second in-field pipeline, wherein the first and second in-field pipelines terminate at a common manifold.

According to a fifth aspect of the invention, there is provided a method for transporting oil from a hydrocarbon field, comprising injecting oil into a flow of gas-condensate in an in-field pipeline. Optionally, injecting oil into the flow of gas-condensate in the in-field pipeline comprises measuring a condensate content in the gas-condensate flow, and injecting the oil into the flow of gas-condensate at a rate based on the condensate content.

BRIEF DESCRIPTION OF DRAWINGS

Some embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

Figure 1 illustrates schematically an example pig receiving apparatus;

Figure 2 is a flow diagram of a method;

Figure 3 illustrates schematically an example portion of a subsea pipeline network, provided with the apparatus of Figure 1;

Figure 4 is a flow diagram of a further method; and

Figure 5 is a flow diagram of a further method.

DETAILED DESCRIPTION

Figure 1 illustrates an example of a pig receiving apparatus 5. The pig receiving apparatus 5 comprises a pig cleaning chamber 6. Generally, the pig cleaning chamber 6 receives a pig from a pipeline, after the pig has pigged the required length of the pipeline. The chamber 6 includes an inlet coupled to an inflow pipe 7, and an outlet coupled to an outflow pipe 8. In this way, the apparatus 5 may be installed at any suitable location in a pipeline network, for example, for receiving a pig from a subsea hydrocarbon pipeline. For instance, the inflow pipe 7 may be a spool coupled to an in field pipeline (not shown in Figure 1), or may be the end portion of the in-field pipeline itself. As such, the inflow pipe 7 typically receives a flow of production fluids PF - generally a mixture of oil, gas and water. A bypass branch 9 connects the inflow pipe 7 to the outflow pipe 8. In normal operation (i.e. when a pig is not being received), a first valve 10 and second valve 11 provided on the inflow 7 and outflow pipe 8, respectively, are closed, whereas a bypass valve 12 provided on the bypass branch 9 is opened. In this way, production fluids PF flowing along the inflow pipe 7 will be diverted along the bypass branch 9. The downstream end of bypass branch 9 feeds back into the outflow pipe. In this embodiment, the downstream end of outflow pipe 8 feeds into a pipeline end manifold (PLEM), as discussed in more detail below; but the outflow pipe may feed into any other subsea node, or into a further pipeline.

In some embodiments, the chamber 6 is internally cylindrical. The inflow pipe 7 is substantially axially aligned with the cylinder axis, whereas the outflow pipe 8 extends, for example, perpendicular to the cylinder axis. While the first valve 10 is depicted in Figure 1 as a shut off valve, any suitable valve (e.g. ball valve, gate valve, etc.) may be used, providing that when first valve 10 is in an open state, the valve 10 aperture is large enough to allow a pig to pass. Due to the alignment of the chamber 6 and inflow pipe 7, the incoming pig is driven by the production fluid PF pressure through the valve 10 and into the chamber 6. At the end of the chamber 6 remote from the inlet/inflow pipe 7, a pig output valve 13 is provided. When the pig output valve 13 is in an open state, the output valve 13 aperture is large enough to allow a pig to pass. At this stage, the pig output valve 13 is closed to keep the pig inside the pig cleaning chamber 6, whereas the second valve 11 is open. As a result, the production fluid PF flowing into the chamber behind the pig flows out via the outlet pipe 8, and onwards downstream.

In some embodiments, the inflow pipe 7 is provided with a pig detector 14. When a pig passes the pig detector 14, the pig detector 14 detects presence of the pig. The pig detector 14 may be coupled to a controller (not shown), which is coupled to the first, second and bypass valves 10, 11, 12. In this way, upon detection of an incoming pig, the detector 14 sends a signal to the controller, and the controller triggers the first 10 and second 11 valves to open, and causes the bypass valve 12 to close. Preferably, the chamber 6 also is provided with a pig detector 15 in order to detect that the pig has been successfully received in the chamber 6. Various pig detector devices are known in the art (such as magnetic or radioisotope pig detectors) and are suitable for use as described herein.

Once the pig is received in the chamber 6, the bypass valve 12 is re-opened and the first valve 10 is closed. As such, production fluid PF flow along bypass pipe 9 resumes. The second valve 11 may also be closed. Optionally, second valve 11 remains open, but an additional check valve 16 is provided to ensure one-way flow from the chamber 6 to outflow pipe 8 (and not vice versa). In either case, normal flow of the production fluids from inflow 7 to outflow pipe 8 resumes, and the pig is trapped inside the chamber 6.

By the time the pig reaches the apparatus 5, it may be carrying a considerable amount of wax, hydrates or dirt. The pig cleaning chamber 6 includes at least one cleaning fluid inlet pipe 17, 18 through which a cleaning fluid CF is injected. In the embodiment shown in Figure 1, a first inlet pipe 17 and second inlet pipe 18 are provided at opposite ends of the pig cleaning chamber 6. The cleaning fluid CF may, for example, be Mono-Ethylene Glycol (MEG) or methanol. The cleaning fluid CF circulates past the pig, removing dirt, wax and/or hydrates from the pig exterior. In the example apparatus shown in Figure 1, the cleaning fluid CF is provided via a supply pipeline 19. In some embodiments, the flow of the cleaning fluid CF through the supply pipeline 19 is driven by a pump at a given distance upstream of the pig receiving apparatus 5 (not shown). In this case, when cleaning is not required (e.g. when a pig is not trapped in the chamber 6), the cleaning fluid CF bypasses the chamber and flows instead along the supply pipeline 19, via an open supply pipeline valve 20. When a pig ready for cleaning, the supply pipeline valve 20 is closed, while a first cleaning fluid inlet valve 21 on the first inlet pipe 17 and/or a second cleaning fluid inlet valve 22 on the second inlet pipe 18 are opened. As such, the cleaning fluid CF is redirected into the chamber 6 via at least one of the inlet pipes 17, 18. In some embodiments, the cleaning fluid CF may be supplied to a storage tank. In this case, a pump is provided for pumping cleaning fluid CF from the tank and into the pig cleaning chamber 6.

The ‘used’ cleaning fluid CF (i.e. the cleaning fluid CF and any debris dislodged from the pig) is removed from the chamber 6 into outflow pipe 8. In some embodiments, the used cleaning fluid CF flows out of the chamber via valve 11 and into the outflow pipe 8. In some embodiments, at least one conduit is provided between the chamber 6 and outflow pipe 8, providing a further path for fluid flow out of the chamber 6 and into to the outflow pipe 8. In the example shown in Figure 1 , a conduit 32 is provided at the far end of the chamber 6, with a valve 24 provided to selectively allow fluid flow along said conduit 32.

In some embodiments, the chamber 6 has a portion with a cross-sectional diameter greater than the largest cross-sectional diameter of the pig, thereby allowing the pig to be surrounded by cleaning fluid CF. For example, the chamber diameter may be 10% greater than the pig diameter. In this case, one or more supports or guiding members may be provided to axially align the pig in the centre of the chamber 6, whilst allowing cleaning fluid CF circulation around the pig periphery.

In some embodiments, the pig cleaning chamber 6 is heated above the WAT to melt wax or hydrates off the chamber walls and, if a pig is in the chamber 6, the pig held therein. In this case, the chamber 6 is coupled to a heater 23. In some embodiments, the heater 23 is an electrical heater. In some embodiments, the chamber 6 comprises a thermally conductive body, and the heater 23 comprises least one resistive heating element coupled to the chamber 6 exterior. A power supply supplies power to the heating element(s), such that when an electric current passes through the heating element(s), heat is generated. The power supply may be provided by the Direct Current supply and Fibre Optic (DC/FO) concept, as described in GB-A-2545365. The dotted line in Figure 1 represents the electrical connection to the chamber 6 in Figure 1, as opposed to coupling via a fluid pipeline, represented by the solid lines. As such, the pig cleaning chamber 6 is warmed, and wax or hydrate accumulation on the pig exterior and/or pig cleaning chamber interior is melted.

In some embodiments, the chamber 6 interior reaches above 40 °C, for example, in the range 40 to 100 °C. In this way, both the WAT and hydrate formation temperature are exceeded, therefore enabling the melting of any wax or hydrate accumulation on the pig and/or on the chamber 6 interior.

In some embodiments, the chamber 6 is provided with at least one thermometer (not shown) to measure the interior temperature of the chamber. The thermometer is coupled to the heater and configured to vary the heater power accordingly in order to regulate the temperature via feedback loop.

In some embodiments, the pig is heated after being captured in the chamber 6 while surrounded by production fluid PF in the chamber 6. Alternatively, or in addition, the pig cleaning chamber 6 may be heated while the pig is surrounded by the cleaning fluid CF. For instance, in some examples, cleaning fluid CF is injected to first displace any production fluid PF contained in the chamber 6 after capturing the pig, and then the heating of the chamber 6 begins. As such, the liquid in the chamber 6 is a mixture of melted wax and hydrate, alongside production fluid PF and/or cleaning fluid CF. The liquid in the chamber 6 is directed back to outflow pipe 8 via the conduit 32, and the conduit 32 is coupled to the heater 23 to maintain liquid flow of the wax and/or hydrates in the liquid mixture carried by the conduit 32. The liquid mixture is injected back into outflow pipe 8 to re-join the flow of production fluids PF. Upon entry into the flow of production fluids PF, the liquid wax cools and solidifies. The liquid mixture may be injected via a mesh or nozzle 34, in order to disperse the liquid as droplets into the production fluid PF. This allows the liquid wax to cool and form small beads or particles of solid wax, which can be readily transported by the fluid flow without subsequent agglomeration or accumulation on the walls of the main pipeline.

In some embodiments, the conduit 32 is coupled to a storage tank, rather than directly to the outflow pipe 8. In this way, liquid from the chamber 6 flows via outlet valve 24 and conduit 32 into the collection tank. In the collection tank, the liquid cools and the wax and/or hydrate component solidifies. The cooled liquid in the tank is then be fed back into the outflow pipe 8, leaving the solid wax and/or hydrates in the tank. The collection tank may be detachable, such that it can be periodically collected and replaced with an empty tank.

In some embodiments, the pig is cleaned using both heating and flushing means. For example, the pig cleaning chamber 6 may be heated as described above, and then flushed using cleaning fluid CF. For instance, after heating, cleaning fluid CF inlet valves 21 and 22, and valve 24 may be opened concurrently, while the remaining valves are closed. In this way, cleaning fluid CF flows into the chamber 6, thereby displacing any fluid or debris out of the chamber via wax outlet valve 24. In some embodiments, the pig is positioned approximately in the centre of pig cleaning chamber 6 during such cleaning, and both the valve 24 and valve 11 are opened concurrently. In this way, cleaning fluid CF can enter and exit the pig cleaning chamber 6 via channels in front of and behind the pig.

In some embodiments, multiple flushing and heating cycles are performed as required until a pig (and the pig cleaning chamber 6) is sufficiently clean.

After cleaning, the clean pig is received by a cassette 26. The cassette 26 is a receptacle for storing at least one pig. Preferably, the cassette 26 interior has a cylindrical shape, with internal diameter approximately equal to the pig diameter, and a length sufficient to accommodate at least one pig. Preferably, the cassette 26 stores multiple pigs. For example, the cassette 26 may be long enough to store ten pigs in series when full. As a result, the pipeline connected to inflow pipe 7 can be pigged multiple times, without having to empty or replace the cassette 26. As such, the frequency at which the apparatus 5 must be accessed is reduced, when compared to a receiver configured to receive a single pig. This is particularly advantageous when the apparatus 5 is installed at a subsea location, wherein accessing the apparatus 5 is generally difficult. In Figure 1, two pigs 33 are stored in the cassette 26. A first end of the cassette 26 has an opening 27 for receiving the pigs from the pig cleaning chamber 6. Pigs 33 from the pig cleaning chamber 6 can pass (via open valve 13) and through the opening 27 into the cassette. The opening 27 may be a valve, similar to the first valve 10 and pig output valve 13 as discussed above.

The pig may be transported from the pig cleaning chamber 6 and into the cassette 26 under fluid pressure. For instance, an injection (or further injection) of cleaning fluid CF into the chamber 6 may be used to drive the pig through the chamber 6 and into the cassette 26 (and any spool or pipework in between). In this case, the cassette 26 is provided with at least one drain. In the example shown in Figure 1, the cassette 26 is provided with a first drain 28 coupled back to the cleaning fluid supply line 18. Alternatively, or alongside the first drain 28, the cassette 26 may also be provided with a second drain 29, connected to output pipeline 8. In either case, suitable valves are provided to selectively allow or disallow one-way drainage along the relevant drain line.

Alternatively, the pig motion may be facilitated with mechanical means. For example, the pig cleaning chamber 6 and cassette 26 may comprise rollers or a conveyor, and a motor to actuate to the rollers or conveyor. Alternatively, the pig cleaning chamber 6 may include a mechanical arm or plunger (not shown) configured to engage the pig, and push or pull the pig along the chamber and/or cassette. The mechanical arm may be telescopic, and comprise a hook or plunger at the end to engage the pig.

Further alternatively, movement from the pig cleaning chamber to the pig receiver cassette can be achieved hydraulically. By providing an hydraulic supply with an inlet located upstream of a pig received in the pig cleaning chamber 6, and an hydraulic return with an outlet located downstream of the hydraulic inlet, i.e. in front of the pig. By this means a low pressure can be created infront of the pig and providing a transport mechanism for the pig throught he valve 13 and towards the cassette 26 through opening 27.

When a pig is not being transported from the pig cleaning chamber 6 into the cassette 26, the cassette 26 is isolated from the rest of the apparatus. By 'isolated', it is meant that any valves and openings coupled to the cassette 26 are closed, such that fluid communication to/from the chamber is prevented. In this way, the cassette 26 is ready for decoupling from the apparatus.

The cassette 26 comprises coupling means, configured to selectively couple or decouple the cassette 26 from the rest of the apparatus. The cassette 26 can then be collected and replaced with an empty cassette 26, for example, by using a Running Tool on a wireline. The full cassette 26 may then be retrieved to an unmanned or manned facility, for example, at the sea surface. Alternatively, the full cassette 26 may be transported to a pig launcher configured to receive the cassette. The clean pigs may then be launched by the pig launcher. Advantageously, a pig can be cycled through the launcher-receiver system multiple times, without having to be retrieved to a surface or onshore facility. In some embodiments, the entire apparatus 5 (i.e. including both the cassette 26 and the pig cleaning chamber 6) is collected and replaced as a whole using a Running Tool.

In an alternative embodiment, it might be possible to retrieve and replace certain components using a remotely operated underwater vehicle (ROV). Further, the cassette 26 may further be integrated into a ROV, i.e. be part of an assembly including a propeller, motor, rudders and control system. The ROV may then travel to the required location (e.g. to a surface facility, or to a pig launcher), as outlined above.

In some embodiments, the pig cleaning chamber 6 and cassette 26 are vertically oriented, such that the pig motion is facilitated by a gravitational force. In this case, opening of the valve 13 allows the pig to fall downwardly until it is captured in the cassette. A spring or compressible buffer may be provided at the lower end of cassette 26 to cushion the pig’s landing. The apparatus 5 may further comprise a frame or housing configured to support the components described above. In this way, the apparatus 5 can be transported, installed and replaced as a single unit.

Figure 2 is a flow chart of a method, including the steps of receiving a pig in a pig cleaning chamber from a pipeline connected to the pig cleaning chamber (S210); cleaning the pig (S220); and receiving the pig from the pig cleaning chamber in a pig storing cassette for accommodating at least one pig (S230).

The inventors have further realised that the pig receiving apparatus 5 described above can be employed advantageously in a pipeline system and wax-management method, as follows. An offshore hydrocarbon field often includes a network of wells distributed across the field. Typically, the production fluids PF from each well flow via an in-field pipeline to a common pipeline end manifold (PLEM). The PLEM, therefore, typically receives a flow of fluid from a plurality of infield pipelines, and output the fluid to a single main pipeline in a ‘many to one’ type connection. Figure 3 illustrates an example portion of this type of pipeline network schematically. In this particular example, two in field lines 1 are provided, though any suitable number of in-field lines 1 could be provided. Each in-field line 1 transports production fluids PF from a wellhead 2 towards the PLEM 3. A main pipeline 4 extending from the PLEM carries the production fluid onwards, for example, towards an onshore facility or a riser to a platform.

Given that the PLEM 3 may be of the order of hundreds of kilometres offshore, pigging over such a distance may be time-consuming and impractical, for at least the following reasons. Firstly, the main pipeline 4 typically has a larger internal diameter (e.g. 24”) than a given in-field line 1 (e.g. 12”), meaning that pig designed to pig in-field line 1 would be ‘lost’ in the main pipeline 4. Furthermore, due to the cooling effect of the surrounding seawater, the production fluids PF typically fall below the WAT in a region of the in-field pipeline 1 extending from wellhead 2 towards the PLEM 3 - leading to wax and hydrate accumulation primarily in this region. Typically, this region extends along the first 15 to 20 km of the in-field pipeline. As such, pigging (or regular pigging) may only be necessary along the in-field pipeline(s) 1, and not any further downstream.

In light of the above, the inventors have realised that it would be beneficial to provide the downstream end of each in-field pipeline 1 with the pig receiving apparatus 5, as illustrated in Figure 3. As such, the difference between Figure 3 and a conventional subsea pipeline network is that each in-field line 1 is provided with the pig receiving apparatus 5 coupled downstream of and proximate to PLEM 3.

Generally, when a pipeline is pigged, the production rate in that pipeline is reduced to 20%-30% of the maximum production rate. Referring again to the system of Figure 3, the inventors have further realised that a method to combat this production loss comprises the steps of: pigging a first in-field 1 pipeline; and while the first in-field pipeline 1 is pigged, increasing the production rate of at least one second in-field pipeline 1, wherein the first and second in-field pipelines terminate at a common manifold 3. As a result, the net rate of production fluid output by the common manifold (e.g. PLEM 3) along the main pipeline 4 may be maintained. This may be advantageous, for example, for components further downstream of the PLEM which operate best under steady-state conditions. Figure 4 is a flow chart of this method.

The inventors have further realised that the system shown in Figure 3 may be relevant to the particular example of hydrocarbon fields comprising gas or gas-condensate sources, but also containing pockets of oil. Typically, the volume of oil in these pockets is small (for example, of the order of 50 million Barrel of Oil Equivalent (BOE)), meaning that the costs for an oil tie back become unprofitable for distances exceeding 60 km or so offshore. As such, the pockets of oil are wasted. To avoid wasting this oil resource, the inventors have realised that the oil from the pockets of oil can instead be injected into the in-field pipeline 1 - providing that the gas flow rate is high enough to carry the droplets of oil to shore. Therefore, the oil must be injected at a suitable rate, as not to overload the gas flow and lead to liquid accumulation in the pipeline. Flow control technologies for injecting water into a gas flow at a controlled rate, such as automatic choke control, are known in the art, and may be suitable to be adapted for injecting oil as described here.

Typically, for gas-condensate fields, the amount of condensate carried by the gas flow is initially high (e.g. 20,000 to 30,000 BOE per day), but drops naturally over time. As such, the capacity for the gas flow to carry oil generally increases with time. Preferably, the condensate content in the gas-condensate flow is measured, and the oil injection rate is varied based on (i.e. as a function of) the condensate content. The condensate content may be measured by any suitable device known in the art for measuring the flow rates of constituent phases, such as a MultiPhase Flow Meter (MPFM). In this way, a decrease (or increase) in condensate content is compensated for with an increase (or decrease) in the oil injection rate. Preferably, the oil is injected a rate such that the net oil and condensate content in the pipeline does not exceed a threshold. Generally, the higher the gas flow rate, the higher the threshold. For instance, for a gas flow of 500 mscfd (thousand standard cubic feet per day), this threshold may be in the range of 20,000 to 30,000 BOE per day. By ensuring the net oil and condensate content does not exceed the threshold, the condensate and/or oil may be carried the full distance of, for example, up to 200 km to shore.

While the above method of producing oil is limited to a lower oil production rate, and therefore typically takes two to three times longer to produce the same oil volume when compared with a standalone oil field, it means that that no new or separate oil pipelines are required. One side effect of the additional oil content carried by the gas flow is that the amount of wax deposition on the in-field pipeline walls may increase. As such, the oil-production method described herein may be beneficially used in conjunction with the pigging apparatus, systems and methods as described above.

In an example, a subsea infield pipeline connects 2 gas condensate wells and 4 oil wells. The infield pipeline is, for example, an uninsulated, 267 mm (10.5 inch) with a minimum length of 15km after the last well connected to the pipeline, in an example the infield pipeline is 25km. Daily gas production of 500mmscf/14.15 mill m³/day from the two wells, and 20,000 barrels of oil per day may be generated from the oil wells; the gas from the two gas wells provides transportation for the oil. It is estimated that 2mm of wax will be built up over 30 days. The pipeline will require pigging every three weeks with a 5 hour pig run.

Each well is ideally monitored in terms of production using, for example, multiphase subsea meters, such as those obtainable from FMC Technologies. There may also be a multiphase meter on each pipeline. Each well (gas and oil) may also have automatic choke control. The control being based on feedback from the well’s multiphase metering.

In an example where the infield pipeline connects first 2 gas wells followed by 4 oil wells in the direction of flow of hydrocarbons towards the PLEM, a subsea pig launcher is located after the gas wells on the pipeline, but before the oil wells. The subsea pig launcher has a 10-pig cassette design. The precise location of the launcher is not essential but it should be towards the well end of the infield pipeline. In accordance with the above embodiments, the subsea pig receiver is located at the other end of the infield pipeline proximate the PLEM as shown in figure 3. In this embodiment the pig receiver also has a 10-pig cassette.

Although the invention has been described in terms of embodiments and examples as set forth above, it should be understood that these embodiments are illustrative only and that the claims are not limited to those embodiments. Those skilled in the art will be able to make modifications and alternatives in view of the disclosure, which are contemplated as falling within the scope of the appended claims. Each feature disclosed or illustrated in the present specification may be incorporated in the invention, whether alone or in any appropriate combination with any other feature disclosed or illustrated herein.

Claims

CLAIMS:

1. An apparatus for receiving a pipeline pig, comprising: a pig cleaning chamber for cleaning a pig received from a pipeline connected to the pig cleaning chamber; and a pig storing cassette for accommodating at least one pig received from the pig cleaning chamber.

2. The apparatus of claim 1, wherein the pig storing cassette accommodates a plurality of pigs.

3 The apparatus of any preceding claim, wherein the chamber has at least one inlet and at least one outlet for a cleaning fluid.

4. The apparatus of claim 3, wherein the cleaning fluid comprises methanol or Mono-Ethylene Glycol, MEG.

5. The apparatus of any one of claims 1 to 4, further comprising a heater coupled to the pig cleaning chamber.

6. The apparatus of any one of claims 1 to 5, wherein the pig storing cassette is detachable from the pig cleaning chamber.

7. The apparatus of any one of claims 1 to 6, wherein the pipeline connected to the pig cleaning chamber is a subsea hydrocarbon pipeline.

8. A method for receiving a pipeline pig, comprising: receiving a pig in a pig cleaning chamber from a pipeline connected to the pig cleaning chamber; cleaning the pig; and receiving the pig from the pig cleaning chamber in a pig storing cassette for accommodating at least one pig.

9. The method of claim 8, wherein the pig storing cassette accommodates a plurality of pigs.

10. The method of claim 8 or 9, wherein cleaning the pig comprises flushing the pig cleaning chamber with a cleaning fluid.

11. The method of any one of claims 8, 9 or 10, wherein before receiving the pig from the pig cleaning chamber in the pig storing cassette, the method further comprises heating the pig cleaning chamber.

12. The method of any one of claims 8 to 11, further comprising: detaching the pig storing cassette and replacing the pig storing cassette with an empty cassette.

13. The method of any one of claims 8 to 12, wherein the pipeline connected to the pig cleaning chamber is a subsea hydrocarbon pipeline.

14. A pipeline system comprising at least one in-field pipeline, wherein the downstream end of the at least one in-field pipeline is provided with the apparatus of any one of claims 1 to 7.

15. A method for wax management in a hydrocarbon pipeline system, comprising: pigging a first in-field pipeline; and while the first in-field pipeline is pigged, increasing the production rate of at least one second in-field pipeline, wherein the first and second in-field pipelines terminate at a common manifold.

16. A method for transporting oil from a hydrocarbon field, comprising: injecting oil into a flow of gas-condensate in an in-field pipeline.

17. The method of claim 16, wherein injecting oil into the flow of gas-condensate in the in-field pipeline comprises: measuring a condensate content in the gas-condensate flow; and injecting the oil into the flow of gas-condensate at a rate based on the condensate content.