GB2280460A - Apparatus for inserting into a conduit - Google Patents

Abstract

Apparatus for inserting into a conduit (50) such as a riser is described. The apparatus includes a tubular member (25) having an external width less than the internal width of the conduit (50), and mounting means (22) to mount the tubular member (25) within the conduit (50). The apparatus has the advantage of reducing the internal flow volume of the conduit (50), and thus reducing the risk of slugging. Pressurised gas for gas lift may be supplied to the annulus between conduit 50 and tube 25, entering tube 25 via apertures 28. <IMAGE>

Description

"Apparatus for Inserting into a Conduit" The invention relates to apparatus for inserting into a conduit, and especially, for inserting into pipelines used in oil and gas production.

Multi-phase pipelines are used in the oil and gas production industry worldwide to transport oil, associated gas and produced water from subsea wells to nearby processing platforms. The use of such multi-phase transport is becoming more important in the North Sea in particular, as a low cost development option for smaller new reservoirs and to drain remote parts of existing reservoirs.

Where the pipeline is connected to a "Fixed" platform, the final part of such pipelines will normally be a vertical "Riser" assembly. This comprises a vertical section of pipework typically 100 to 200 meters in length connecting subsea the end of the pipeline at the platform base to the processing equipment on the platform topsides. Where the pipeline connects to a Floating Production Vessel (FPV) the Riser will normally be a flexible pipe in an "S" shape.

In certain pipeline/riser configurations "Slugging" flow can occur. This condition refers to the situation where the flowrate of the separate gas and liquid phases out of the top of the riser is not steady, and oscillates between largely (or all) gas and largely (or all) liquid. This situation can lead to three significant problems, typically: a) Flooding of the inlet gas/liquid separator vessel due to a large "slug" of liquid arriving, the volume of which is more than the available liquid capacity in this vessel. This will lead to Emergency Shutdowns, and in extreme cases may cause liquid carryover to the process gas flare system.

b) Unsteady operating conditions in the topsides equipment. This can lead to failure to meet product specifications; typically oil content in produced water discharge, and water content in export oil, both due to difficulties in achieving a stable oil/water interface. In addition, this can also lead to problems in control of gas compressors due the unsteady flow of feed gas to such units from the gas/liquid separators, which may result in flaring of some gas.

c) High stress loads may be imposed on riser pipework.

Slugging may typically be worst when pipeline fluid flowrates are below the pipeline design flows. Two scenarios can be considered.

a) New Design Products It is becoming normal practice to carry out a full dynamic analysis of the proposed pipeline design during the early stages of a project, to check that the predicted slug size and frequency are acceptable, and that severe slugging is not expected. Such an analysis would typically cover the full range of expected fluid flowrates over the reservoir life.

Fluid flows at the end of life are generally much lower than the initial production rates, and the pipeline design must accommodate both the maximum and minimum rates. This leads to conflicting design objectives; the pipeline diameter must be large enough to accept the maximum flow condition without excessive pressure drop, but must not be too large otherwise excessive slugging may occur at the low flow conditions towards end of field life. The final pipeline diameter may therefore be a compromise, and in some cases maximum production rates must be sacrificed by selecting a diameter less desired in order to avoid slugging problems at end of life low flow conditions.

In some cases, the slugging problem, along with increased heat loss at end of life, may lead to the choice of dual pipelines of smaller diameter, with only one line being used at low flow conditions. This option will not be economically viable for many marginal field developments.

A further method available to new projects is to install "Gas Lift" on the riser. This normally requires a separate small diameter gas riser to be run to the platform base, which is then connected to the multiphase production riser. By injecting a constant flow of gas to the riser, slugging effects can be mitigated and severe slugging avoided. However, there is a cost penalty for the additional riser piping, and the gas lift rates required to be effective in the full riser bore can be prohibitive. Again, marginal fields may not be able to stand the additional costs associated with this.

b) Production Lower Than Expected Some subsea fields in production in the North Sea experience slugging conditions due to actual flows being lower than designed for. This is typically due to one or more of the following: . Reservoir performance below that expected, Wellbore blockage due to scale formation or asphaltene deposition, Water cut higher than expected, Pipeline solids build up (typically wax/asphaltenes).

In these conditions, the low flows lead to higher liquid hold up in the pipeline, and higher slugging potential if the pipeline/riser configuration is susceptible to this.

In accordance with the present invention, apparatus for inserting into a conduit comprises a tubular member having an external width less than the internal width of the conduit, and mounting means to mount the tubular member within the conduit, wherein the apparatus reduces the internal flow volume of the conduit.

The invention is particularly suitable for conduit associated with risers. However, it may also be applied to steeply inclined pipelines.

The invention has the advantage that by reducing the flow volume of the conduit slugging problems can be reduced and can usually be mitigated, especially when used in conjunction with gas lift.

Preferably, the tubular member may have through bores in its walls to permit fluid and pressure communication between the inside of the tubular member and the annulus between the outside of the tubular member and the inside of the conduit.

Typically, the mounting means could comprise projections on the outside surface of the tubular member which engage with the internal surface of the conduit. Preferably, the projections are of a uniform length so that the tubular member is located concentrically within the conduit. In one example of the invention, the projections are typically in the form of fin formations on the external surface of the tubular member and preferably extend along the outside of the tubular member in a direction which is typically parallel to the longitudinal axis of the tubular member.

However, other forms of projections could be used and it is not essential that the projections extend in a direction parallel to the longitudinal axis. For example, it is possible that the projections could be in the form of a helix, a spiral or a serrated disc.

Typically, the apparatus may include a number of tubular members which may be coupled together by a connection means along the length of the conduit.

Typically, the connection means for coupling individual tubular members together could comprise bolted joints, lightweight clamps or screwed connections.

Alternatively, the apparatus may include a reeled flexible pipe which is inserted into the conduit, or any other suitable form of tubular.

The invention is particularly advantageous in relation to conduits in which fluid flows through the conduits in an upwards direction and particularly, where the fluid comprises a mixture of gas and liquid.

Preferably, the conduit may be a pipeline and is typically a multi-phase pipeline which conveys oil, associated gas and produced water from subsea wells to nearby processing platform. Typically, the pipeline may be a riser which extends from the seabed or adjacent to the seabed to processing equipment on the surface.

Preferably, the tubular member is fabricated from a lightweight material, and for example, could be thin wall steel, rubber, plastic, Revlar, glass re-enforced plastic (GRP) or a combination of any of these materials.

Preferably, the apparatus also comprises a hanger means to connect the top of the apparatus to the conduit, where the apparatus is used in a non-horizontal orientation, such as where the conduit is a riser.

Typically, the hanger means comprises a hanger spool located on the conduit adjacent the top end on the apparatus.

Typically, the apparatus is removable from the conduit.

Preferably, the apparatus may also have means to permit a gas lift system to be installed in a riser and typically, this is provided by ensuring that an annulus is created between the tubular member and the inside of the riser.

Typically, maximum benefits will be obtained from the apparatus if the tubular member extends beyond the base of the vertical riser section and into the horizontal section of the conduit which connects to the riser base. The tubular member may therefore typically include a flexible section at, or adjacent to, its lower end which extends around the bend at the base of the riser. Typically, to hold the end of the flexible section in place and to provide sufficient rigidity to allow cleaning pigs to enter the tubular member, the end of the flexible section may be connected to a packer arrangement, which is typically fixed to the internal surface of the horizontal conduit. Typically, the packer may be similar to those used for downhole well operations, and may be of an inflatable or a self gripping type. Typically, the horizontal conduit may be a pipeline.

Preferably, the gas lift injection point, when present, is also located in the horizontal conduit at the base of the riser.

Examples of apparatus for inserting into a conduit in accordance with the invention will now be described with reference to the accompanying drawings in which: Fig. 1 is a cross-sectional view showing the lower most end of a first example of a sleeve for insertion into a riser; Fig. 2 is a cross-sectional view along the line AA in Fig. 1; Fig. 3 is a cross-sectional view through a central section of the first example of the sleeve for fitting into a riser; Fig. 4 is a side view of first example of a hanger spool for fitting to the top of an uppermost sleeve to support the apparatus shown in Figs. 1 to 3; Fig. 5 shows a side view of a second example of a hanger spool; Fig. 6 shows a cross-sectional view of second example of a sleeve for fitting into a riser; Fig. 7 shows a cross sectional view of an example of a flexible sleeve for use adjacent the lower end of a riser;; and, Fig. 8 is a cross sectional view along the line AA of Fig. 6.

Fig. 1 shows an insert 10 for inserting into a rigid vertical riser on a fixed platform. The insert 10 comprises a lower riser insert sleeve 1 and a number of upper sleeves 5 (only 1 shown in Fig. 1). The lower sleeve 1 is connected to the lowermost upper sleeve 5 by a sleeve clamp 3 which is fixed using clamp fasteners 4, as shown in Fig. 2. Connected to the lower end of the lower sleeve 1 is a funnel section 6 which funnels fluid into central passageway 7 of the insert 10. In the lower sleeve 1 are a number of apertures 8 (only 4 shown) which permit fluid communication between the central passageway 7 of the insert 10 and the outside of the insert 10.

Attached to the external surface of the lower sleeve 1 and funnel section 6 are six rubber positioners 2 which are spaced equidistant around the outside surface of the lower sleeve 1 and the funnel section 6. Although in this example the positioners are rubber, the positioners may be manufactured from any suitable material.

Fig. 3 shows a central section of the insert 10 which shows a sleeve 5 coupled to the lower sleeve 1 at its lower end and coupled to another sleeve 5 at its upper end by means of sleeve clamps 3 and clamp fasteners 4.

Rubber positioners 2 are also attached to the outer surface of the sleeves 5, as shown in Fig. 3.

In use a number of sleeves 5 would be coupled to each other, as shown in Fig. 3, and extend all the way up the riser to the surface platform and typically, the insert 10 would be hung from the platform by means of a hanger spool 11, as shown in Fig. 4. The hanger spool 11 includes a top flange 13 and a lower flange 14 and there are bolt holes 15 through each flange in order to permit connection and fixing of the hanger spool 11 to other apparatus on the platform. Hanging down from the lower flange 14 is a sleeve support bracket 16 which may be coupled to the uppermost sleeve 5 using a sleeve clamp 3 and clamp fastener 4, in a similar manner to that shown in Figs. 1 and 3. The hanger spool 11 also has a central through bore 17 which communicates with the central bore 7 in the insert 10.In addition, the hanger spool 11 has a gas lift inlet 18 to permit gas to be pumped into the annulus between the insert 10 and the riser into which the insert 10 is inserted. This permits gas lift operations to be performed, as gas forced into the annulus between the insert 10 and riser, through the gas lift inlet 18, will be forced out of the apertures 8 in sleeve 1 to perform a gas lift operation.

During installation into a riser, the funnel section 6 is coupled to the lower most end of the sleeve 1 and the assembly of the sleeve 1 and funnel section 6 is inserted into the riser. The sleeve 5 is then coupled to the top of the sleeve 1 by means of the sleeve clamp 3 and clamp fasteners 4. The insert 10 is then lowered further into the riser and another sleeve 5 is connected to the top of the previous sleeve 5. This process of adding further sleeves 5 continues until the insert 10 and sleeves 5 extend to the platform where the hanger spool 11 may be connected to the top sleeve 5 and fixed in position on the platform to suspend insert 10 within the riser.

When the insert 10 is in position in the riser, fluid flowing to the riser is funnelled into the central section 7 of the insert 10 by means of the funnel section 6 and because the central section 7 is of a reduced diameter compared with the original diameter of the riser, the volume through which the fluid must flow to reach the platform is reduced. Due to apertures 8, the pressure in the annulus between the sleeves 1, 5 and the riser can equalise with the fluid pressure within central section 7 so that the sleeves 1, 5 do not have to contain pressure. This has the advantage of permitting relatively lightweight material to be used to fabricate the insert 10.

In addition, the insert 10 would also generally be removable which would facilitate intelligent pigging of the original riser, should this be necessary.

The invention also has the advantages of providing a relatively simple, cheap and reliable retrofit solution to mitigate slugging effects and multi-phase pipelines by reducing effective riser volume, during the design phase of a project pipeline diameter need not be constrained by end of life slugging conditions as an insert 10 could be installed into the riser during the lifetime of the riser. Furthermore, the insert has the advantage of providing a retrofit gas lift, which in addition to mitigating severe slugging will reduce the static back head back pressure on the wells, and so allow increased production. In addition, multidiameter cleaning pigs can be run through the pipeline and riser with the insert installed.

Figs. 6 and 7 show a second example of an insert within a rigid vertical riser 50 on a fixed platform. The insert comprises a lower riser flexible insert sleeve 21 and a number of upper sleeves 25 (only one shown in Fig. 6). The lower sleeve 21 is connected to the uppermost sleeve 25 by a sleeve clamp 23 which may be either screwed, bolted, or connected by other suitable means. Connected to the lower end of the lower sleeve 21 is a funnel section 26 which funnels fluid into the central passageway 27 of the sleeves 21 and 25. In the lower sleeve 21 are a number of apertures 28 (only three shown) which permit fluid communication between the central passageway 27 of the sleeves 21 and 25 and the outside of these sleeves.

Attached to the external surface of the lower sleeve 21 are rubber positioners 24 which are arranged in a helical or spiral formation around the outside surface of the lower sleeve 21 in such a way as to centralise the lower sleeve within the conduit, and to allow a gas path via the annulus 30. Although the positioners 24 in this example are rubber, the positioners 24 could be manufactured from any suitable material.

Fig. 6 shows the central section of the insert which shows two sections of sleeve 25 coupled to another sleeve 25 at its upper and lower ends by means of sleeve clamps 23 which may be either screwed, bolted or connected by some other suitable means. Rubber positioners 22 are also attached to the outer surface of the sleeves 25, as shown in Fig. 6, to act as centralisers.

Around the flexible sleeve 21, a spiral or helical type positioner 24 is used This helps to enhance the flexibility of the lower section for ease of insertion into the bent section of the riser. The positioners 22 are shown in more detail in Fig. 8, where it can be seen that cut away sections 40 provide fluid communication above and below each positioner 22.

In use a number of sleeves 25 would be coupled to each other, as shown in Fig. 6, and extend all the way up the riser to the surface platform and typically, the topmost insert sleeve 25 would be hung from the platform by means of a hanger spool 31, as shown in Fig. 5. The hanger spool 31 is an element which can be bolted between existing riser top flanges 33 and 34 through bolt holes 35 through each flange in order to permit connection and fixing of the hanger spool 31 to other apparatus on the platform. The hanger spool 31 includes a support shoulder 36 and a retaining ring 37 which clamps the uppermost sleeve 25 in position. In addition, the hanger spool 31 has a gas lift inlet 38 to permit gas to be pumped into the annulus between the insert sleeve 25 and the riser 50 into which the insert sleeve 25 is to be inserted.This permits gas lift operations to be performed, as gas forced into the annulus between the insert sleeve 25 and the riser, through the gas lift inlet 28, will be forced out of the apertures in sleeve 21 to perform a gas lift operation.

If no suitable flange is available at the top of the existing production riser, the design may be revised to use fully flexible insert sleeves, as sleeve 21, in place of rigid sleeves 25.

During installation into a riser, the funnel section 26 is coupled to the lower most end of the sleeve 21 and the assembly of the sleeve 21 and funnel section 26 is inserted into the riser. The sleeve 25 is then coupled to the top of the sleeve 21 by means of the sleeve clamp 23. The insert is then lowered further into the riser and another sleeve 25 is connected to the top of the previous sleeve 25. This process of adding further sleeves 25 continues until the sleeves 25 extend to the platform where the hanger spool may be connected to the top sleeve 25 and fixed in position to the platform to suspend the complete insert within the riser.

As an alternative to using multiple sleeves 25 connected to one another, where possible a continuous sleeve may be used, to be installed by reeling one length into the conduit, complete with positioners 22.

When the complete insert is in position a riser base packer element 20 would be set by inflating the seal element via an umbilical run within the annulus 30.

Alternatively, if a self setting packer is used, this would have been installed and set as an initial operation prior to installing the first sleeve 21 and 25. Yet another alternative would be to use a pump down type packer. The exact details of which type of packer 20 is used will be dependent on the local conditions in each installation, but in all cases it is envisaged that an existing type of well downhole packer can be adapted to suit the requirements of the insert.

When the insert is in position in the riser 50, fluid flowing to the riser is funnelled into the central section 27 of the insert sleeves 21 and 25 by means of the funnel section 26 and because the central section 27 is of a reduced diameter compared with the original diameter of the riser 50, the volume through which the fluid must flow to reach the platform is reduced. Due to apertures 28, the pressure in the annulus between the sleeves 21, 25 and the riser can equalise with the fluid pressure within the central section 27 so that the sleeves 21, 25 do not have to contain pressure.

This has the advantage of permitting a relatively lightweight material to be used to fabricate the insert sleeves 25.

In addition, the insert would also generally be removable which would facilitate intelligent pigging of the original riser, should this be necessary.

The invention has the advantages of providing a relatively simple, cheap and reliable retrofit solution to mitigate slugging effects in multi-phase pipelines by reducing effective riser volume. During the design phase of a project, pipeline diameter need therefore not be constrained by end of life slugging conditions as an insert could be installed into the riser during the lifetime of the riser. Furthermore, the insert has the advantage of providing a retrofit gas lift facility, which in addition to mitigating severe slugging will reduce the static back pressure on the wells, and so allow increased production. In addition, multi-diameter cleaning pigs can be run through the pipeline and riser with the insert installed.

Although the invention is described above with reference to riser systems, it may also be suitable for steeply inclined pipelines.

Improvements and modifications may be made without departing from the scope of the invention.

Claims (10)

1. Apparatus for inserting into a conduit comprises a tubular member having an external width less than the internal width of the conduit, and mounting means to mount the tubular member within the conduit, wherein the apparatus reduces the internal flow volume of the conduit.

2. Apparatus according to claim 1, wherein the tubular member has at least one through bore in a side wall thereof.

3. Apparatus according to claim 1 or claim 2, wherein the mounting means comprises projections on the outside of the tubular member which engage with the internal surface of the conduit, in use.

4. Apparatus according to any of the preceding claims, wherein the apparatus includes a number of tubular members and connection means to couple the tubular members in end-to-end relationship.

5. Apparatus according to any of the preceding claims, wherein the conduit conveys fluid.

6. Apparatus according to any of the preceding claims, wherein the conduit is substantially vertical or steeply inclined.

7. Apparatus according to claim 6, the apparatus also including hanger means to couple the top of the apparatus to the conduit.

8. Apparatus according to any of the preceding claims, the apparatus also including gas injection means to permit gas to be inserted into an annulus between the conduit and the tubular member, in use.

9. Apparatus according to any of the preceding claims, the tubular member comprising a flexible section.

10. Apparatus for inserting into a conduit, substantially as hereinbefore described, with reference to the accompanying drawings.