WO2008035090A1

WO2008035090A1 - Method of inhibiting hydrate formation

Info

Publication number: WO2008035090A1
Application number: PCT/GB2007/003589
Authority: WO
Inventors: Keijo Kinnari; Catherine Labes-Carrier; Gunnar Flaten; Knud Lunde; Jan Hundseid
Original assignee: Statoil ASA
Current assignee: Equinor ASA
Priority date: 2006-09-21
Filing date: 2007-09-21
Publication date: 2008-03-27
Anticipated expiration: 2009-03-21
Also published as: GB0618656D0; GB2447027A

Abstract

The invention provides a method of treatment of hydrocarbon fluid flowing through a pipeline comprising an in-field flowline and downstream thereof a larger internal cross-sectional area trunkline, said method comprising introducing a gas hydrate formation inhibitor into hydrocarbon gas at a site in said pipeline and downstream thereof cooling the gas in said pipeline to a temperature close to or below the water dew point thereof whereby to condense water from the gas such that the water dew point of the gas entering said trunkline is close to or lower than the ambient temperature.

Description

Method of inhibiting hydrate formation

This invention relates to improvements in and relating to gaseous hydrocarbon transport through pipelines, and in particular to a method of inhibiting hydrate formation in such pipelines, especially at the upper inner surface.

Gaseous hydrocarbon, e.g. natural gas, is often transported for large distances along pipelines, e.g. from an offshore well head to an onshore receiving facility (for example a gas liquefaction plant) . Such gaseous hydrocarbons generally have some moisture content and the pressure and temperature conditions within the pipeline can reach the zone in which formation of solid gas hydrates can occur. If build up of solid gas hydrates is severe, the hydrocarbon flow rate may drop or the pipeline may even become blocked. Since removal of gas hydrate is not a straightforward matter, it is normal to inject continuously into the hydrocarbon flow a chemical inhibitor of gas hydrate formation, e.g. methanol or monoethylene glycol.

At the well-site, well stream from several well-heads is conducted through pipes, referred to as in-field flowlines, to a module where the well streams are combined. Subsequent flow to the end-of-pipeline receiving facility is through a relatively large cross- sectional area trunkline. Such combination may take place in more than one stage with the final combination module before the trunkline often being referred to as a pipeline end module (PLEM) .

The hydrocarbon flows that are combined need not of course be from the same field centre and the terms flowline and trunkline as used herein simply require an upstream relatively lower and a downstream relatively higher internal cross-sectional area respectively with flows from the former being combined to create the flow for the latter; in both cases, the terms will generally relate to conduits from or downstream of the well-head.

We have realised that injection of a chemical inhibitor does not entirely avoid the risk of gas hydrate formation since condensation of the chemical inhibitor will generally occur preferentially relative to condensation of the water vapour in the hydrocarbon gas . As a result, water condensation downstream of the point at which inhibitor condensation is essentially complete can result in inhibitor-free, or inhibitor-poor, water droplets or film forming on the inner walls of the pipeline at positions where the temperature and pressure are such that gas hydrate formation can occur.

The resulting risk of gas hydrate formation can however be reduced if the flowing hydrocarbon gas, downstream of chemical inhibitor injection, is exposed to cooling sufficient to cause the water vapour in the gas to condense before the gas enters the trunkline.

Thus viewed from one aspect the invention provides a method of treatment of hydrocarbon fluid, particularly gas, flowing through a pipeline comprising an in-field flowline and downstream thereof a larger internal cross- sectional area trunkline, said method comprising introducing a gas hydrate formation inhibitor into hydrocarbon gas at a site in said pipeline and downstream thereof cooling the gas in said pipeline to a temperature close to or below the water dew point thereof whereby to condense water from the gas such that the water dew point of the gas entering said trunkline is close to or lower than the ambient temperature. In the method of the invention, the inhibitor is conveniently introduced in substantially dry form and at or downstream of the well-head such that it flows along the pipeline in the same direction as the hydrocarbon, i.e. it is introduced in the manner conventional for inhibitors. No substantial countercurrent inhibitor flow will thus occur.

By "close to" in this context it its meant that the temperature difference is no more than 15°C, more especially no more than 10⁰C, particularly no more than 5°C. Particularly preferably cooling is to below the water dew point and condensation is such that the water dew point of the gas entering the trunkline is below the ambient temperature.

Viewed from a further aspect the invention provides a hydrocarbon gas pipeline comprising an in-field flowline and downstream thereof a larger internal cross-sectional area trunkline, said pipeline having a port for the introduction of a gas hydrate formation inhibitor and having downstream of said port and upstream of said trunkline a gas cooler.

While water condensation may still occur in the in-field flowlines at positions downstream of the position at which most of the chemical inhibitor has condensed out of the gas phase, this is of relatively low concern since in the smaller cross-sectional area in-field flowlines the gas flow is more turbulent than in the larger cross-sectional area trunkline and hence condensed inhibitor will be splashed over the internal surfaces of the flowlines .

It will thus be appreciated that the condensed aqueous phase will travel along the pipeline with the hydrocarbon in the hydrocarbon flow direction and water/hydrocarbon separation will generally take place at the downstream end of the pipeline. Recycling of aqueous condensate into an upstream section of the pipeline will not normally occur, although inhibitor extracted from the condensate may be recycled.

In the method and apparatus of the invention, the cooling of the gas to close to or below the dew point may be effected by heat transfer to the surroundings of the pipeline and/or to a coolant fluid and/or by expansion of the gas. In the first case, the cooler in the pipeline will generally comprise a section of pipeline in which the internal surface area to volume ratio is increased relative to upstream and downstream sections, e.g. by the provision of internal cooling fins or by the use of one or more smaller internal diameter sections of pipeline in parallel and/or in series. In the second case, the cooler in the pipeline takes the form of a section of pipeline of greater internal cross sectional area than the upstream section of the pipeline, optionally preceded by a section of pipeline of smaller internal cross-sectional area than the section upstream thereof, i.e. the pipeline may be provided with a "choke" followed by an expansion zone. The cooler is at or upstream of the trunkline, i.e. the section of the pipeline leading to the receiving facility (e.g. an onshore location or a remote storage or delivery site) . It may thus for example be at or upstream of a PLEM or it may take the form of a choke valve at the beginning of the trunkline.

Where the inlet temperature for the hydrocarbon entering the trunkline is T₁, the ambient temperature at position x along the trunkline is T^x _a, the temperature of the hydrocarbon in the trunkline at position x is T^x _t and the dew point for the hydrocarbon in the trunkline at position x is T^x _d, it is important that T^x _a < T^x _t for most of the trunkline. However some expansion of the gas phase in the trunkline may occur and accordingly there may thus be a temperature difference (drop) between T₁ and T^x _t such that T^x _c < T^x _d. The gas hydrate formation inhibitor should thus desirably be present in the liquid phase entering the trunkline at sufficient concentration that its gas phase concentration at T^x _t is sufficient to prevent hydrate formation in any water condensing in the trunkline. The required inhibitor concentration may be calculated using conventional means and if required further inhibitor may be added, e.g. to the liquid phase, following the cooling to close to or below the dew point and the resultant water condensation, e.g. at or adjacent a PLEM or at a point along the trunkline.

Since in-field flowlines can typically run for up to about 20 km in length before reaching the PLEM, the cooler may typically be up to tens of kilometers from the well-head. If desired coolers may be located in early-stage flowlines, i.e. flowlines from which the flow is subsequently combined to flow through a greater cross-sectional area flowline which leads in turn to the still greater-cross-sectional area trunkline.

An alternative however is to place the PLEM at a distance from the well-heads, generally at least 20 km, particularly at least 35 km, such that heat transfer to the environment from the in-field flowlines ensures that sufficient water has condensed out from the gas that the dew point of the gas in the trunkline starts close to or below and remains close to or below the ambient- temperature at the trunkline. Once again the gas hydrate formation inhibitor should thus desirably be present in the liquid phase entering the trunkline at sufficient concentration that its gas phase concentration is sufficient to prevent hydrate formation in any water condensing in the trunkline. The required inhibitor concentration may be calculated using conventional means and if required further inhibitor may be added. The use of such long in-field flowlines, however is generally undesirable since gas flow needs a lower pressure differential for larger cross-sectional tubes.

If desired, a water separator may be placed downstream of the point at which cooling to close to or below the dew point and hence condensation occurs . Typically such a separator would be installed at or adjacent a PLEM. Water from the separator may be treated, e.g. following transportation to a surface facility, to retrieve the gas hydrate formation inhibitor which can then be reused. With the use of a water separator, liquid build-up and pressure drop in the trunkline downstream of the separator may be reduced. The separator may take any convenient form, e.g. a water trap provided with a valved outlet through which the water may be expelled into a water transport line itself optionally provided with a pump.

In general, in the method of the invention, the in-field flowlines will have internal diameters of less than 30", e.g. 16" to 28", while the trunkline will generally have an internal diameter of 30" or greater, e.g. up to 50", more preferably up to 44". These diameter values are typical but should not be considered essential for the performance of the invention.

By ambient temperature for any position along the trunkline is meant the temperature of the surroundings of the trunkline at that position. For subsea pipelines, ambient temperature is generally >-2°C, more typically >4°C.

The hydrate inhibitor is preferably introduced at, before or shortly after the well head, e.g. within up to 5Om of the well head, more preferably up to 10m. As mentioned above, further inhibitor may be introduced at or adjacent a PLEM or within a trunkline.

The inhibitor may be any of the chemicals conventionally used as gas hydrate formation inhibitors, e.g. methanol or monoethylene glycol, and may be used in conventional quantities .

The method and apparatus of the invention are particularly suitable for underwater hydrocarbon wells, e.g. offshore wells, especially where the ambient temperature of the surrounding water reaches temperatures as low as about -2°C to +5°C.

However the method and apparatus are also suited for onshore operation, in particular where trunklines are exposed to cold weather conditions, e.g. arctic and subarctic tundra such as >50°N in North America and >60°N in Northern Europe or Asia, or at high altitudes.

The pipeline treatment according to the invention has the added advantage that trunkline corrosion will be reduced as the same water condensation mechanism controls corrosion. Thus in the method and apparatus of the invention, if corrosion control is of primary concern, e.g. where ambient temperatures are such that hydrate formation is unlikely, the use of the inhibitor can be omitted. Thus viewed from a further aspect the invention provides a method of treatment of hydrocarbon fluid flowing through a pipeline comprising an in-field flowline and downstream thereof a larger internal cross- sectional area trunkline, said method comprising cooling the gas in said pipeline to a temperature close to or below the dew point thereof whereby to condense water from the gas such that the dew point of the gas entering said trunkline is close to or lower than the ambient temperature .

The invention will now be illustrated further with reference to the accompanying schematic drawing.

Referring to Figure 1, there is shown a pipeline 1 leading from sub-sea well heads 2 to an onshore receiving facility 3. The pipeline comprises in-field flowlines 4 leading from the well heads 2 to a PLEM 5 and a spool 6 leading from the PLEM to the trunkline 7. Gas hydrate inhibitor is injected into the pipeline at injection ports 8 at the well heads. Coolers 9 are located in the flowlines 4 and take the form of a choke 10 followed by an expansion zone 11. Liquid condensed in the coolers flows along the pipeline.

Claims

Claims :

1. A method of treatment of hydrocarbon fluid flowing through a pipeline comprising an in-field flowline and downstream thereof a larger internal cross-sectional area trunkline, said method comprising introducing a gas hydrate formation inhibitor into hydrocarbon gas at a site in said pipeline and downstream thereof cooling the gas in said pipeline to a temperature close to or below the water dew point thereof whereby to condense water from the gas such that the water dew point of the gas entering said trunkline is close to or lower than the ambient temperature .

2. A method as claimed in claim 1 wherein cooling is effected by expansion.

3. A method as claimed in claim 1 wherein cooling is effected by passage through a choke valve.

4. A method as claimed in claim 1 wherein cooling is effected by heat-transfer to the environment or to a coolant fluid from said flowline.

5. A method as claimed in any one of claims 1 to 4 wherein said inhibitor is introduced into said pipeline at or downstream of the well-head.

6. A method as claimed in any one of claims 1 to 5 wherein further gas hydrate formation inhibitor is introduced into said pipeline downstream of the site at which the gas therein is cooled to beneath its water dew point.

7. A method as claimed in any one of claims 1 to 6 wherein the quantity of gas hydrate inhibitor introduced into the hydrocarbon is such that its concentration in the trunkline is sufficient to prevent gas hydrate formation therein.

8. A hydrocarbon gas pipeline comprising an in-field flowline and downstream thereof a larger internal cross- sectional area trunkline, said pipeline having a port for the introduction of a gas hydrate formation inhibitor and having downstream of said port and upstream of said trunkline a gas cooler.

9. A method of treatment of hydrocarbon fluid flowing through a pipeline comprising an in-field flowline and downstream thereof a larger internal cross-sectional area trunkline, said method comprising cooling the gas in said pipeline to a temperature close to or below the water dew point thereof whereby to condense water from the gas such that the water dew point of the gas entering said trunkline is close to or lower than the ambient temperature.

10. A method as claimed in claim 9 wherein cooling of the gas is effected so as to reduce corrosion of said pipeline.