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EP-4741031-A2 - A DRAIN APPARATUS FOR A SUBSEA PIPELINE

EP4741031A2EP 4741031 A2EP4741031 A2EP 4741031A2EP-4741031-A2

Abstract

The present invention provides a drain apparatus for use in a subsea pipeline to remove liquid from a multiphase flow in the subsea pipeline. The drain apparatus comprises a first channel for carrying a multiphase flow comprising liquid and gas phases; and liquid extraction means for extracting the liquid phase from the multiphase flow in the first channel. The internal diameter of the first channel is substantially the same as an internal diameter of a subsea pipe arranged to carry the multiphase flow in the subsea pipeline, such that a pig travelling along the subsea pipe can pass through the first channel. The present invention also provides a subsea pipeline comprising a subsea pipe for transporting a multiphase flow subsea; and at least one drain. The at least one drain is disposed partway along a gradient in the subsea pipe to reduce liquid holdup.

Inventors

  • LIÉBANA YESTE, Laura
  • TREVELYAN THOMAS, Lee

Assignees

  • Trevelyan Trading Ltd.

Dates

Publication Date
20260513
Application Date
20170821

Claims (15)

  1. A subsea pipeline (600) comprising: a subsea pipe (30) for transporting a multiphase flow subsea; and at least one drain (200; 220; 300; 400; 500; 550; 600; 700; 800; 1000; 2100; 2400) for removing liquid from the multiphase flow in the subsea pipe, wherein the at least one drain is disposed partway along a gradient in the subsea pipe to reduce liquid holdup.
  2. The subsea pipeline according to claim 1, wherein said gradient in the subsea pipe comprises an upward or downward gradient of a topographical feature of the seabed.
  3. The subsea pipeline according to claim 1 or 2, wherein the at least one drain is disposed at a point along the gradient at which liquid holdup in the subsea pipeline would otherwise cause slugging to occur.
  4. The subsea pipeline according to claim 1, 2 or 3, wherein the at least one drain is disposed about 15% of the way along the gradient when measured from the bottom of the gradient.
  5. The subsea pipeline according to claim 1, 2 or 3, wherein the at least one drain comprises a first drain disposed at a first position along a first gradient and a second drain disposed at a second position along a second gradient, the second gradient being more steeply inclined than the first gradient, and wherein a distance from a bottom of the first gradient to the first position is greater than a distance from a bottom of the second gradient to the second position.
  6. The subsea pipeline according to any one of the preceding claims, wherein the at least one drain comprises: a first channel (20) for carrying a multiphase flow comprising liquid and gas phases, wherein ends of the first channel are fluidly coupled inline with the subsea pipe; and liquid extraction means (11; 12; 14; 16; 18) for extracting the liquid phase from the multiphase flow in the first channel, wherein the internal diameter of the first channel is substantially the same as an internal diameter of a subsea pipe arranged to carry the multiphase flow in the subsea pipeline, such that a pig (800) travelling along the subsea pipe can pass through the first channel.
  7. The subsea pipeline according to claim 6, wherein the at least one drain further comprises: a first storage tank (2131a; 2431a) disposed beneath the liquid extraction means, the first storage tank being arranged to receive liquid from the liquid extraction means, wherein the at least one drain apparatus is configured to support the liquid extraction means a certain height above the seabed so as to accommodate the first storage tank without a need to excavate the seabed, the first channel further comprising curved sections between the open ends and the liquid extraction means to accommodate a difference in height between the liquid extraction means and the subsea gas pipeline, and a bend radius of each of said curved sections is configured such that the pig travelling along the subsea pipe can pass through each of said curved sections.
  8. The subsea pipeline according to claim 7, wherein the at least one drain further comprises: a second storage tank (2131b; 2431b) disposed beneath the liquid extraction means, the first and second storage tanks being disposed on opposite sides of the drain apparatus.
  9. The subsea pipeline according to claim 6, 7 or 8, comprising a plurality of drains (700) each comprising at least one pump (42) coupled to the outlet so as to receive liquid from the outlet, wherein an inlet of each pump is arranged to receive liquid from a pump of another drain apparatus such that each drain acts as a pumping station for moving liquid to the next drain along the subsea pipeline.
  10. The subsea pipeline according to any one of claims 6 to 9, further comprising: a second channel configured to bypass the first channel, wherein the liquid extraction means is disposed on the second channel.
  11. The subsea pipeline according to any one of the preceding claims, further comprising a subsea umbilical line (46) having at least one first conduit (47) coupled to an outlet of the drain and configured to receive liquid from the outlet and transport it to the surface or an offshore terminal.
  12. The subsea pipeline according to any one of the preceding claims, further comprising at least one second conduit (24) coupled to an injection port of the drain and configured to deliver hydrate inhibitor from the surface or an offshore terminal to the injection port.
  13. The subsea pipeline according to claim 12, wherein the hydrate inhibitor is at least one of Ethylene glycol [MEG], Methanol or a low dose hydrate inhibition chemical, and/or wherein the injection port comprises at least one valve (2117a, 2117b) for controlling the rate of flow of hydrate inhibitor into the first channel.
  14. The subsea pipeline according to any one of the preceding claims, further comprising: at least one shut-down drain (210) for removing liquid from the subsea pipeline during a shut-down period before a subsequent start-up of the subsea pipeline, each shut-down drain being disposed at a geographical low point along the subsea pipeline.
  15. A method of operating a subsea pipeline according to claim 13, the subsea pipeline comprising a first drain (200; 220; 300; 400; 500; 550; 600; 700; 800; 1000; 2100; 2400)having at least one first injection port (24) and at least one first valve (2117a, 2117b) for controlling the rate of flow of hydrate inhibitor into the first channel of the first drain, and a second drain (200; 220; 300; 400; 500; 550; 600; 700; 800; 1000; 2100; 2400) having at least one second injection port (24) and at least one second valve (2117a, 2117b) for controlling the rate of flow of hydrate inhibitor into the first channel of the second drain, the first drain being disposed closer to a well head (50) than the second drain, the method comprising: controlling the at least one first valve and the at least one second valve such that more hydrate inhibitor is injected into the first drain than the second drain.

Description

Field The present invention relates to a drain apparatus and a subsea pipeline. More particularly, the present invention relates to a drain apparatus for use in the subsea pipeline. Background When transporting production gas (which can be later processed into Liquefied Natural Gas (LNG)) along a subsea pipeline, water and other liquid components or mixtures precipitate out of the multiphase flow due to heat and pressure loss. This results in a reduction in pressure driving the system due to the gravitational effect on the condensing water, which means generally production gas cannot naturally flow more than about 80 - 140 km from a well head. Furthermore, the effect, known as "slugging", increases the back pressure on the well and shortens the production plateau, where it would have been much greater if liquids had not been in the system (in other words, a "dry gas" system). To solve this problem, both increasing and decreasing the bore of the main carrier pipe within the pipeline have been tried. However, increasing the bore was found to make the slugging worse due to an increase in gravitational pressure losses. Decreasing the bore was found to increase pressure loss due to friction. Therefore, it is necessary to remove as much liquid from the multiphase flow as possible, as early as possible. To that end, it is known to incorporate a single separator at the well head. However, this still does not produce a pseudo dry gas system. Moreover, it is known to use subsea drains (or, "Low Point Drains" (LPDs)), positioned at the lowest part of a gradient, to remove liquid flowing back down the pipe in the pipeline that precipitated out due to temperature and pressure variations. However, the particular designs of these LPDs, and their location, is shown not to have had a great effect on system efficiency, as indicated by comparing the plots represented by diamonds and squares in Figure 17. Moreover, present designs of LPDs do not allow continuous pigging operations, with subsequent negative effect on the system's integrity. Minimising the effect of gravitational pressure losses enables pipelines to have pipes with greater bore diameters, which in turn lowers the pressure drop per unit distance. Reducing the pressure drop also increases the production plateau and allows more resources to be extracted from the ground. Aspects of the present invention aim to address one or more of the aforementioned drawbacks inherent in prior art subsea pipelines, while still allowing continuous pigging operations. Summary According to a first aspect of the present invention, there is provided a drain apparatus for use in a subsea pipeline to remove liquid from a multiphase flow in the subsea pipeline, the drain apparatus comprising: a first channel for carrying a multiphase flow comprising liquid and gas phases; andliquid extraction means for extracting the liquid phase from the multiphase flow in the first channel, wherein the internal diameter of the first channel is substantially the same as an internal diameter of a subsea pipe arranged to carry the multiphase flow in the subsea pipeline, such that a pig travelling along the subsea pipe can pass through the first channel. Advantageously, the first aspect provides a means for transporting gas greater distances by removing liquid from a subsea pipe in a subsea pipeline at any chosen point along the length of the subsea pipe. By being able to be positioned anywhere along the subsea pipe, rather than at the well head, more liquid can be removed from the system. The drain apparatus can be positioned anywhere along the subsea pipe by virtue of it being configured to allow pigging operations to continue uninterrupted between a well head and a terminal on the land. The liquid extraction means may be configured so as not to permit the multiphase flow to bypass the pig as the pig passes through the first channel, such that a pressure differential can be maintained across the pig. In some embodiments, the liquid extraction means comprises at least one opening formed in a wall of the first channel to permit liquid to be extracted through the at least one opening, and a distance between the furthest downstream point of the at least one opening and the furthest upstream point of the at least one opening is less than 1.5 times the internal diameter of the first channel. For example, in some embodiments the distance between the furthest downstream point of the at least one opening and the furthest upstream point of the at least one opening is less than 0.8 times the internal diameter of the first channel. The drain apparatus may be installed in a subsea pipeline, and the drain apparatus may be disposed partway along a gradient in the subsea pipe to reduce liquid holdup. The liquid extraction means may be a slug catcher or a separator. The liquid extraction means may comprise an inlet to receive liquid from the first channel, and a chamber in fluid communication with the inlet. The liquid ex