FIELD OF THE INVENTION

The present invention relates to removal of hydrate plugs from target subsections of subsea piping installations, in particular pipelines that conduct hydrocarbons, such that the flow of hydrocarbons is not impeded. The method and the system according to particular embodiments of the present invention are particularly advantageous for being retrofitted to existing subsea piping installations which have no previously installed equipment for this purpose.

BACKGROUND

Methods for offshore hydrocarbon exploitation using sub-sea wells are well known. The hydrocarbons produced at the sub-sea wells are typically delivered to an offshore production platform via one or more sub-sea piping installations, which include equipment such as choke valves, manifolds, flowlines and sub-sea pipelines positioned in areas of deep waters remote from shore. Consequently, some hydrocarbon conducting subsea piping installations rest on the seabed at depths where the temperature of the sea water surrounding the installation is conducive to formation of hydrates.

Unprocessed natural gas typically contains water, as well as other contaminant species. One of the problems to be faced in the case of transport of unprocessed natural gas, is the risk of hydrate formation. Hydrates are stable crystalline "calthrate" solids having the outward appearance of ice with gas molecules trapped in an ice-like cage structure. It is known that Cl to C4 hydrocarbons as well as hydrogen sulphide (H ₂ S) and carbon dioxide (CO ₂ ) readily form hydrates at low temperatures (below 20 degrees Celsius) and high pressure. When the temperature is raised above the so-called "hydrate dissolution temperature" the hydrates dissolve or melt, liberating the trapped gas and producing a water-containing liquid.

It is a known problem that the flow of hydrocarbons in sub-sea piping installations can be blocked by hydrate plugs when the whole cross-section of a pipe is blocked by formation of hydrates. It is also known to remove hydrate plugs in sub-sea pipelines using a technique known as "depressurization", in which the pressure is monitored at each end of the blocked pipeline whilst a differential in pressure is maintained on either side of the plug to encourage it to partially dissolve and start to move

Methods have also been developed to avoid hydrate formation. Hydrate formation can be prevented by removing water from the well stream. It is also known to place thermal insulation around pipelines to try to reduce the risk of hydrate formation. The formation of gas hydrates can be thermodynamically suppressed by adding hydrate inhibitors to the hydrocarbon flow such as methanol or glycol and/or inhibiting nucleation and growth of hydrates by using particular polymers or surfactants. Where there are large volumes of water in the well stream, the consumption of such hydrate inhibitors is very high as is the cost associated with regeneration of these chemicals using distillation.

Direct electrical heating (DEH) of the pipelines for prevention of formation of hydrates has also been proposed (see, for example International Patent Publication Number WO2004/111519 and International Patent Publication Number WO 2006075913). DEH is based on the principle of applying electrical alternating current to a metallic conductor in order to generate heat due to ohmic loss. Using prior art DEH systems, electric cables are connected along the whole length of a subsea pipeline such that the pipeline is caused to become an active conductor of current in a single-phase circuit formed by power supply cables and the pipeline itself. In such prior art DEH systems, the full length of a subsea pipeline DEH is used to maintain the temperature of the hydrocarbons being conducted through the pipeline over the equilibrium temperature for hydrate formation such that the formation of hydrate plugs can be avoided. Such systems are designed to run either intermittently to avoid hydrate formation from occurring during prolonged unforeseen operational stand-stills or scheduled maintenance periods or continuously to avoid hydrates if flow rates and temperatures are low. Such systems are also designed to melt hydrates and/or hydrate plugs if they have formed in the pipeline, with heating occurring over the full length of the pipeline. In general terms, prior art DEH systems are designed to be at least partially pre-installed prior to laying of the pipeline.

Existing pre-installed DEH systems are very demanding with respect to equipment and costs. As a result such prior art DEH systems rely on careful design of the systems occurring prior to installation of the pipeline. There is a need for a DEH system to be retrofittable to an existing sub-sea piping installation that has had nothing pre-installed on the pipeline to facilitate later retrofit. Alternatively, there is a need for a DEH system to be deployable on demand at any location on a pipeline over a range of lengths to remove hydrate plugs from existing sub-sea piping installations.

SUMMARY OF THE INVENTION

According to a first aspect of the present invention there is provided a method for selective direct electric heating of a target subsection of a subsea piping installation, which target subsection is at least partially constructed of a ferrous material and is identifiable or suspected as having been blocked by a hydrate plug and, the method characterized in that the target sub-section is heated to a temperature above the hydrate dissolution temperature of the hydrate plug for a given pipeline pressure and whereby heating is achieved using direct electric heating applied to the target subsection at a high frequency, preferably not less than 150 Hz, the target subsection having a length of not greater than 500m.

For greater control, the frequency may be variable. In one form, the frequency is variable in response to a feedback signal generated by one or more temperature sensing means.

In one form the frequency is in the range of 150 to 250 Hz. Alternatively or additionally, the target subsection may have a length in the range of 30 to 500m.

According to a second aspect of the present invention there is provided a direct electric heating system for selectively heating a target subsection of a subsea piping installation, which target subsection is at least partially constructed of a ferrous material and is identifiable as having been blocked by a hydrate plug, the direct electric heating system comprising: a. a power source stationed at a surface deployment location, the power source being capable of delivery of sufficient current to raise the temperature in the target subsection above the hydrate dissolution temperature for a given pipeline pressure; b. first and second electrical connectors mounted, in use, at a spaced apart interval along the length of the subsea piping installation whereby the target subsection is defined by the space between the first and second electrical conductors; and, c. a riser cable having an upper end in electrical communication with the power source and a lower end in electrical communication with the first and second electrical conductors via a piggyback cable; d. the system characterized in that the system is retrofittable to an existing sub-sea installation, the system being dimensioned such that the target sub-section can be heated to a temperature above the hydrate dissolution temperature of the hydrate plug for a given pipeline pressure and whereby heating is achieved using direct electric heating applied to the target subsection at a frequency not less than 100 Hz, the target subsection having a length of not greater than 500m.

In one form, the first and second connectors are mounted to the subsea piping installation at ROV accessible locations. The subsea piping installation may be a simple pipeline or a jumper spool. It is to be understood that there is no requirement that the target subsection be located in a plane extending horizontally parallel to the seabed.

In one form, the power source is a single phase alternating current power source stationed at a surface deployment location. The surface deployment location may be a fixed offshore platform or a surface vessel.

The riser cable may be made up of a plurality of conductors, including at least one forward conductor and at least one return conductor, and in one form, the riser cable has an upper end electrically connected to the power source and a lower end terminating at a junction plate or box in which the forward conductor is electrically isolated from the return conductor.

In one form, the system further comprises one or more temperature sensors placed at spaced apart intervals along the length of the target subsection to provide a feedback signal that can be used to regulate the frequency of the power supply.

In one form, the system further comprises one or more anodes electrically connected to an external wall of the subsea piping installation for transferring residual current to the seawater. At least one of the anodes may be provided in a horseshoe bridge configuration. For ease of retrofittability, each of the first and second electrical connectors may be a wet- mateable connector. In one form the wet-mateable connector may be a bracelet clamp provided with one or more contact device(s) and at least one hot stab connector.

According to a third aspect of the present invention there is provided a method of selective direct electric heating of a target subsection of a subsea piping installation substantially as herein described with reference to and as illustrated in the accompanying drawings.

According to a fourth aspect of the present invention there is provided a system for selectively heating a target subsection of a subsea piping installation substantially as herein described with reference to and as illustrated in the accompanying drawings.

DESCRIPTION OF THE DRAWINGS

In order to facilitate a more detailed understanding of the nature of the invention embodiments will now be described in detail, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 is a schematic elevation view of illustrating one embodiment of the DEH system of the present invention being deployed from a fixed offshore platform;

Figure 2 is a schematic elevation view of illustrating one embodiment of the DEH system of the present invention being deployed on a jumper spool from a surface vessel;

Figure 3 is a cross-sectional view of one embodiment of a riser cable;

Figure 4 is a schematic view of one embodiment of the DEH system showing the junction box and the use of anode sleds;

Figure 5 is a cross-sectional view showing one arrangement of the piggyback cable location relative to a layer of insulation;

Figure 6 is a cross-section view showing an alternative arrangement to that illustrated in Figure 5; Figure 7 illustrates one example of an anode sled in a horseshoe configuration; and,

Figure 8 illustrates one example of a bracelet clamp for use as one or both of the first and second wet-mateable connectors including one hot stab connector.

DETAILED DESCRIPTION OF THE INVENTION

The present invention will now be described in greater detail with reference to the accompanying drawings wherein several preferred embodiments of the present invention are set forth. Whilst the description to follow focuses on direct electric heating of subsea pipelines that conduct hydrocarbons, the present invention is also relevant for water conducting pipelines, such as pipelines for water injection. The present invention is equally applicable to sub-sea piping systems other than pipelines, for example, a rigid pipe spool located between a manifold and a flow line connection, referred to in the art as "a jumper spool". Whilst the description to follow is focused on the removal of hydrate plugs, the present invention is equally applicable to the removal of ice plugs or wax plugs. Those skilled in the art will recognized that the accompanying drawings are schematic representations only and therefore, many items of equipment that would be needed in a commercial facility for successful operation have been omitted for the sake of clarity. Such items might include, for example, flow controls, level, temperature and pressure controls, pumps, motors, filters, additional valves, cabling etc. It will be readily appreciated that a person skilled in the art would be able to include such items in accordance with standard engineering practice.

With reference to Figure 1 there is illustrated a first embodiment of a direct electric heating ("DEH") system (10) in accordance with the present invention. The DEH system (10) is used for selectively heating a target subsection (12) of a subsea piping installation (14). In Figure 1, the subsea piping installation (14) is a pipeline. In a second embodiment illustrated in Figure 2, for which like reference numerals refer to like parts, the subsea piping installation (14) is a jumper spool extending between a pipeline end termination station (15) and a manifold (17). There is a skin effect from induction of current that allows heat to be generated when the target subsection is at least partly constructed from a ferrous alloy. Thus, for the DEH system (10) to be effective, the target subsection (12) must be constructed of a ferromagnetic material such as a pipeline steel, or produced as a composite pipe having at least one layer of ferromagnetic material.

The target subsection (12) is a section of the subsea piping installation (14) which has been identified as having been blocked by a hydrate plug using conventional methods known to those skilled in the relevant art. The DEH system (10) is dimensioned such that the target subsection (12) can be heated to a temperature above the hydrate dissolution temperature of the hydrate plug (which is dependent on the given pipeline pressure), so as to cause complete melting of the hydrate plug. The amount of energy required to melt the hydrate plug is dependent on such relevant factors as the total heat transfer coefficient of the subsea piping installation materials of construction and the length, wall thickness and cross-sectional area of the target subsection.

The DEH method and system of the present invention is intended to be used such that direct electric heating is applied to a target subsection having a length of not greater than 500m and using a high frequency, preferably not less than 150 Hz. To this end, alternating current is utilized at a frequency of at least 150 Hz, preferably in the range of 150 to 250 Hz, which is substantially higher than the usual frequency of 50 Hz or 60 Hz utilized in the prior art. Such relatively high frequencies are avoided in the past art as resulting in unacceptably low restrictions in the length of pipeline installation to be heated.

Using the method and system of the present invention, it is possible to use these relatively high frequencies because the DEH system is being used only to heat a short target subsection of the subsea piping installation with a view to melting a hydrate plug, whereas prior art DEH systems are designed to heat the entire or a long subsection of the pipeline subsea piping installation to prevent hydrates from forming at all. Unlike prior art DEH systems, the present invention is not intended for use on a continuous basis to avoid hydrate formation, but rather for deployment to remove hydrate plugs after they form. Thus, the DEH system is retrofitted to an existing subsea piping installation with the first and second electrical connectors being installed where needed. The present invention thus results in significant cost savings compared with prior art systems in which electrical connectors are positioned at regular intervals along the full length of the pipeline, including being positioned at locations where hydrate plugs may never form, whereas in the present invention, electrical connectors are positioned only where needed. The DEH system (10) of the present invention includes a single phase alternating current power source (16) stationed at a surface deployment location (18), the power source (16) being capable of delivery of sufficient current to raise the temperature in the target subsection (12) above the hydrate dissolution temperature for a given pipeline pressure. A suitable surface deployment location would include capacity for handling cables as well as other equipment as required for deployment of a remotely operated vehicle ("ROV"). Suitable surface deployment locations include a fixed offshore platform illustrated schematically in Figure 1 or the deck of a ship or "surface vessel" as illustrated schematically in Figure 2.

The DEH system (10) includes a riser cable (20) which forms part of an electrical circuit connecting the power source (16) with the target subsection (12) of the subsea piping installation (14). In use, the riser cable extends downwardly from the surface deployment location through the sea. For safety reasons, it is preferable for the riser cable to be of sufficient length to assume the shape of a catenary to minimise the risk of stress being applied to the riser cable in rough sea conditions. With reference to Figure 3, the riser cable (20) is made up of a plurality of conductors or cores, including at least one forward conductor (22) and at least one return conductor (24), the function of which is described in greater detail below. The riser cable (20) has an upper end (26) electrically connected to the power source (16) and a lower end (28) terminating at a junction plate or box (30). At the junction box (30) the forward conductor (22) is electrically isolated from the return conductor (24) as best seen in Figure 4.

The DEH system (10) further comprises first and second electrical connectors (32 and 34, respectively) mounted, in use, at a spaced apart interval along the length of the subsea piping system (14) whereby the target subsection (12) is defined by the distance between the first and second electrical connectors (32 and 34, respectively). These retrofittable first and second electrical connectors (32 and 34, respectively) are mounted at any Remote Operated Vehicle ("ROV") accessible locations along the length of the subsea piping installation (14) when a hydrate plug has been identified as forming a blockage. It is common for existing subsea piping installations to be provided with some form of heat insulation or at least some type of surface treatment or protective coating. Prior to retrofitting the first and second electrical connectors (32 and 34, respectively) to the existing subsea pipeline system (14), any existing coatings or heat insulation are first removed locally and this step can be performed using an ROV. For maximum efficiency of heat transfer to the target subsection and to reduce ohmic losses to the surrounding seawater, the outer thermal insulation around the target subsection is replaced, reinstated or introduced before the current is turned on.

In the embodiment illustrated in Figure 1, the first connector (32) is located at an end of the target subsection to be heated, with the second connector (34) being located adjacent to the junction box (30). In this arrangement, it can be readily understood that the target subsection itself serves as the return conductor for the current circuit as described in greater detail below. At junction box (30), the forward conductor (22) of the riser cable (20) is electrically connected to the first connector (32) via a "piggyback cable" (36) and the return conductor (24) is electrically connected to the second connector (32). In this way, a current circuit is formed from the power source (16) down through the forward conductor (22) of the riser cable (20), through the piggyback cable (36) to the first electrical connector (32), and then back through the target subsection (12) of the subsea piping system (14) to the second connector (34) and back to the power source through the return conductor (24) of the riser cable (20). By passing current through this circuit, the target subsection is heated using the power supply (16).

The term "piggyback cable" as used throughout this specification refers to a length of cable that is arranged to lie along the length of the target subsection (12) in close proximity to the exterior surface of target subsection. The piggyback cable (36) extends along the full length of the target subsection (12). In the embodiment illustrated in Figure 5, the piggyback cable (36) is laid alongside the outside of the target subsection (12) with a protective layer of insulation (37), such as a layer of seabed soil or gravel, a blanket or a mattress, being laid over both. In an alternative embodiment illustrated in Figure 6, the layer of insulation (37) is laid over the target subsection (12) to retain heat generated by the DEH system (10), with the piggyback cable (36) being laid in close proximity to but outside of the layer of insulation (37).

For greater control, one or more temperature sensors (40), for example one or more thermocouples, are placed at spaced apart intervals along the length of the target subsection (12) to provide a feedback signal that can be used to regulate the frequency of the power supply (16) to ensure the temperature of the contents in the target subsection is raised above the hydrate dissolution temperature for the given pipeline pressure. The target subsection (12) is earthed to the sea bed (41) or the surrounding water by means of a suitable earth connection. In the embodiments illustrated in Figures 1, 2 and 4, one or more anodes or anode sleds (42), is electrically connected to an external wall of the subsea piping installation (14) to transfer residual current to the seawater to protect against a coating breakdown which could lead to excessive localised corrosion. In the embodiment illustrated in Figure 4, two anode sleds (42) are used, with one located adjacent to the first connector (32) and the second one located adjacent to the second connectors (34). In one form, the anode sleds (42) are provided in a horseshoe bridge configuration as illustrated in Figure 7.

For ease of retrofit, each of the first and second electrical connectors is preferably a "wet- mateable" connector. A "dry mate" is a type of connector known in the art which is usually made above the waterline or "topsides" and intended to be mated only once. A "wet- mateable" connector is one that can be mated and de-mated subsea. Suitable wet-mateable connectors are known in the art and in this regard, the first and second connectors may be releasably fastened in place using, for example, screw-type connectors or permanently mounted in position using, for example friction welding.

One particular embodiment of a wet-mateable connector in the form of a bracelet clamp (44) for use as one or both of the first or second connector (32 or 34, respectively) is illustrated in Figure 8. The bracelet clamp (44) comprises first and second arms ((46) and (48), respectively) pivotally connected together at a hinge (50) to allow the clamp to be moved from an open position in which the clamp is placed in position around the circumference of one end of the target subsection (12), and a closed position in which the first arm (46) is locked in position relative to the second arm (48) using a locking means (52), such as an ROV actuated self-locking latch closure, to secure the clamp to the pipe. An electrical circuit between the bracelet clamp and the target subsection (12) is established by installing one or more contact devices (54). In the embodiment illustrated in Figure 8, one such contact device is shown in the form of an ROV-operable screw in connector. The clamp (44) is further provided with at least one hot stab connector (56) which can be manufactured integrally with the bracelet clamp or fitted to the bracelet clamp in situ after installation of the clamp to the target subsection. In the case of the first connector (32), the stab connector (56) is provided to facilitate ROV attachment of the piggyback cable (36). In the case of the second connector (34), the stab connector (56) is used for electrical connection to the return conductor (24). The clamp (44) is further provided with a grounding connection (58) to facilitate connection to one or more of the anodes (42).

Now that the preferred embodiments of the present invention have been described in detail, the present invention has a number of advantages over the prior art, including the following: a) the system is retrofϊttable to existing subsea piping installations which have no DEH equipment pre-installed; b) retrofitting the first and second connectors means that they are less exposed to mechanical damage during laying operations; c) the hydrates are melted "on demand" over a relatively short period of time at a reduced cost to operating a DEH system over the full length of a pipeline; d) the present invention can be used over a range of typically much shorter lengths than prior art DEH installations allowing for optimisation of the system design; e) the DEH system can be deployed, recovered and redeployed at a new location; f) the present invention can be worked together with one or both of chemical injection and depressurization to reduce downtime; and, g) the diameter of the piggyback cable laid across the target subsection can be smaller than prior art DEH cables and less expensive, making them easier to deploy.

It will be apparent to persons skilled in the relevant art that numerous variations and modifications can be made without departing from the basic inventive concepts. For example, the riser cable may be electrically connected to a sub-sea manifold which forms part of the sub-sea piping system, the sub-sea manifold having been provided with pre-installed sub-cables capable in turn of being wet-mateably connected to the first and second connectors. All such modifications and variations are considered to be within the scope of the present invention, the nature of which is to be determined from the foregoing description and the appended claims.