Subsea processing of well fluids

Abstract

A wax control element for subsea processing of well fluids in a wellstream comprises a bundle of flowlines within an elongate tensile structure. That structure defines inlet and outlet ends and has cooling and heating provisions that act on the flowlines, in use, to promote deposition of wax in the flowlines and subsequent entrainment of wax in the wellstream.

Claims

1. A method of installing or developing a subsea oil or gas production system by installing a prefabricated wax control unit at an installation location, the unit comprising an elongate wax control element disposed between a first towhead at an upstream end of the element and a second towhead at a downstream end of the element, the method comprising: towing the unit to the installation location with an elongate tensile structure of the wax control element in tension between the towheads; sinking the unit at the installation location; connecting the towheads to other elements of the production system so that the unit may be operated to pass the well fluid along the wax control element; and passing well fluid along the wax control element between the towheads while cooling and periodically heating flowlines of the wax control element; wherein cooling the flowlines comprises pumping cooling water along the wax control element in mutually opposed directions between the towheads.

2. The method of claim 1, comprising performing hydrate control on the well fluid in the first, upstream towhead.

3. The method of claim 2, wherein power and chemicals are distributed to templates and wellheads of the system from the second, downstream towhead.

Description

(1) In order that the invention may be more readily understood, reference will now be made, by way of example, to the accompanying drawings, in which:

(2) FIG. 1 is a schematic diagram of a prior art solution involving subsea processing of a wellstream, in which a processing unit is disposed downstream of a pipeline;

(3) FIG. 2 is a schematic diagram of another prior art solution involving subsea processing of a wellstream, in which a processing unit is disposed upstream of a pipeline;

(4) FIG. 3 is a schematic diagram of a subsea processing solution of the invention employing a towable unit comprising a pipeline bundle with a towhead at each end;

(5) FIG. 4 is a top plan view of a towable unit of the invention in a practical form;

(6) FIG. 5 is a schematic plan view of an upstream towhead used in a towable unit of the invention;

(7) FIG. 6 is a schematic plan view of a downstream towhead used in a towable unit of the invention;

(8) FIGS. 7a and 7b show, respectively, towing and installation steps performed with the towable unit of the invention;

(9) FIG. 8 is a top plan view of a subsea production installation incorporating the towable unit of the invention;

(10) FIG. 9 is a perspective view of a variant of the upstream towhead shown in the towable unit of FIG. 4;

(11) FIG. 10 is a top plan view of a towable unit of the invention including the variant of the upstream towhead shown in FIG. 9;

(12) FIG. 11 is a schematic plan view of a prior art solution for wax control; and

(13) FIG. 12 is a schematic cross-sectional view of a pipeline bundle for wax control in accordance with the invention.

(14) Reference has already been made to FIGS. 1 and 2 of the drawings to describe subsea processing solutions known in the prior art. FIG. 3 illustrates the invention in a similarly simplified, schematic style; again, like numerals are used for like features. Thus, the direction of production flow is again from left to right as shown, from a wellhead 10 to a riser 16. The riser 16 is shown here in the form of a riser column or tower like that of FIG. 1, but it may of course take another form such as a catenary.

(15) In FIG. 3, the pipeline 12 laid across the seabed 14 between the wellhead 10 and the riser 16 is replaced by a pipeline bundle 26. Also, the termination structures 18 of FIGS. 1 and 2 are replaced by an upstream towhead 28 at an upstream end of the pipeline bundle 26 and a downstream towhead 30 at a downstream end of the pipeline bundle 26. Thus, the upstream towhead 28 is interposed between the wellhead 10 and the pipeline bundle 26 whereas the downstream towhead 30 is interposed between the pipeline bundle 26 and the riser 16.

(16) In accordance with the invention, either and preferably both of the towheads 28, 30 comprises facilities for processing the wellstream before it flows up the riser 16, and so also replaces the processing unit 20 of FIGS. 1 and 2. Thus, either and preferably both of the towheads 28, 30 serves as an integrated termination structure and processing unit. The invention therefore aims to mitigate several of the drawbacks of subsea processing by grouping subsea processing units with the pipeline bundle 26. Also, distributing the processing units among the towheads 28, 30 spreads the weight of the process system and locates the units appropriately at the inlet or outlet end of the pipeline bundle 26.

(17) The pipeline bundle 26 and the towheads 28, 30 together constitute a single towable unit 32 that, highly advantageously, may be fabricated and tested onshore before being towed as one unit to an installation site. Once fabricated onshore, the whole unit 32 may be pulled into the water, as is already done in the oil and gas industry with the pipe bundles that form hybrid riser towers.

(18) In the context of towing, the upstream towhead 28 may be described as a leading towhead and the downstream towhead 30 may be described as a trailing towhead. Towing and installation will be described in more detail below with reference to FIGS. 7a and 7b of the drawings.

(19) The pipeline bundle 26 acts in tension between the towheads 28, 30 during towing, with tensile loads being borne by the pipes of the bundle 26 or, preferably, principally or exclusively by an outer pipe or other protective structure that surrounds the pipes of the bundle 26. This arrangement will be described in more detail below with reference to FIG. 12 of the drawings.

(20) In the simplified arrangement shown in FIG. 3, jumper pipes or spools 22 connect the upstream towhead 28 to the wellhead 10 and the downstream towhead 30 to the riser 16. However, the towheads 28, 30 may be connected to the wider subsea production system in other ways, for example via manifolds, and so need not be connected as directly to the wellhead 10 and to the riser 16.

(21) As FIG. 6 will show later, a power umbilical as shown in FIG. 1 may extend from a surface unit (not shown) to one of the towheads 28, 30 to provide power to its processing facilities. Advantageously, power may be transmitted from one towhead 28, 30 to the other towhead 28, 30 through power cables in the pipeline bundle 26. This allows one umbilical to be connected to just one of the towheads 28, 30 and yet to provide power to both of the towheads 28, 30.

(22) FIG. 4 shows the towable unit 32 in a practical form, with a long pipeline bundle 26 connecting a larger upstream towhead 28 and a smaller downstream towhead 30. As will be explained, the upstream towhead 28 includes a manifold in this instance and so is optimised to gather fluid production from multiple wellheads. A variant of the upstream towhead 28 that encompasses the wellhead or provides drilling slots will be described later with reference to FIGS. 9 and 10.

(23) Moving next to FIGS. 5 and 6, these show the towheads 28, 30 in more detail. Specifically, FIG. 5 shows the upstream towhead 28 whereas FIG. 6 shows the downstream towhead 30.

(24) The upstream towhead 28 shown in FIG. 5 comprises an elongate tubular steel lattice frame 34 of generally rectangular cross-section. As a non-limiting example, the frame 34 may be considerably in excess of forty metres long and more than eight metres high and wide. The frame 34 comprises four parallel longitudinal members 36 joined by cross-members 38, with gaps between the cross-members 38 providing access to bays for installation, maintenance and replacement of processing and flow-handling equipment carried by the towhead 28. The processing and flow-handling equipment is largely carried within the cross-section of the frame 34, although some elements of that equipment may protrude from the frame 34.

(25) FIG. 5 shows processing and flow-handling equipment carried by the upstream towhead 28. At its upstream end, the frame 34 of the towhead 28 defines a bay that houses a manifold 40 for in-field flowlines and for water injection. At its downstream end, the frame 34 has a tapering nose structure 42 to anchor one end of the pipeline bundle 26 against tensile loads. From there, the pipeline bundle 26 extends over a considerable distance (typically 1.5 to 2.0 km) to the downstream towhead 30, which will be described later with reference to FIG. 6. The frame 34 also carries a system control module 44 that may be connected through the pipeline bundle 26, as shown, to control the downstream towhead 30.

(26) It has been noted above that where the processed well fluid is crude oil, there is a threat of wax deposition as the temperature of the wellstream falls below the wax formation temperature. Wax deposition is controlled by wax control features in the pipeline bundle 26. This is the purpose of a cooling water pump 46, which drives cooling water along the pipeline bundle 26 as will be explained later with reference to FIGS. 11 and 12 of the drawings. However, there is also a threat of hydrate formation as the temperature of the wellstream falls below the hydrate formation temperature. Consequently, much of the equipment between the manifold 40 and the pipeline bundle 26 is concerned with hydrate control.

(27) The effect of hydrate formation can be significantly reduced, indeed almost eliminated, by separating water out of the wellstream. Consequently, the hydrate control equipment of the upstream towhead 28 comprises two separation stages 48, 50 downstream of the manifold 40, followed by a coalescer 52. Subsea separation of water is a known and qualified technology that typically leaves less than 2% of water in the wellstream after a two-stage separation. The small amount of water remaining in the wellstream can be handled by adding anti-agglomerates to the wellstream at a hydrate control unit 54 after separation and coalescence.

(28) Separated water is cleaned in a hydro-cyclone 56 and then re-injected into the reservoir via the manifold 40 by using a booster pump 58 and a water injection pump 60.

(29) Routine optional steps of gas separation and sand removal may also be performed by equipment in the upstream towhead 28, although that equipment has been omitted from FIG. 4 for clarity.

(30) Pigging facilities (which may be removable) are provided to test and maintain the pipeline and particularly the pipes of the pipeline bundle 26. A removable pig launcher 62 is shown in FIG. 4. However, it should be noted that systematic pigging such as is required by WO 2006/068929 is obviated by first separating water from the crude oil as described above, which drastically reduces the residual quantity of wax and hydrates.

(31) Turning now to the downstream towhead 30 shown schematically in FIG. 6, this also comprises an elongate tubular steel lattice frame 64 of generally rectangular cross-section comprising four parallel longitudinal members 66 joined by cross-members 68. The downstream towhead 30 is somewhat shorter than the upstream towhead 28 but is suitably of similar cross-sectional size.

(32) The frame 64 of the downstream towhead 30 carries a pipeline connector 70 communicating with the pipeline bundle 26 for downstream transport of the wellstream. For example, there may be cold-flow transport of the wellstream along a long tie-back pipeline on the seabed, or the wellstream may be carried by a jumper or spool into an adjacent riser structure.

(33) A second cooling water pump 72 mirrors the cooling water pump 46 of the upstream towhead to drive cooling water along the pipeline bundle 26. This duplication of water pumps 46, 72 minimises pumping losses and provides redundancy to maintain cooling in the event of failure or downtime due to maintenance.

(34) The frame 64 of the downstream towhead 30 also carries a power station 74 that takes electrical power from a riser umbilical 76. The power station 74 supplies power to: an umbilical distribution system 78; to other equipment carried by the frame 60, such as the cooling water pump 72; and also via the pipeline bundle 26, as shown, to power the upstream towhead 28. The umbilical distribution system 78 includes connection points for plugging in umbilicals as well as fuses and transformers. Those features are routine and need no elaboration here.

(35) In summary, therefore, the upstream towhead 28 includes: connections to wellhead(s) or to a production manifold; water separation; removed water treatment and/or re-injection; cold flow conditioning for transportation; cold-water circulation systems and local heating systems for wax removal. However cold-water circulation systems and local heating systems could also, or alternatively, be located in the downstream towhead 30. It is also possible for pigging facilities to be located on either towhead 28, 30.

(36) Turning next to FIGS. 7a and 7b of the drawings, pipeline installation by towing is well known in the art. In this respect, a convenient towing technique for use with the invention is the Controlled Depth Towing Method (CDTM), which is described in technical papers such as OTC 6430 noted previously. This technique involves far fewer installation steps than in prior art subsea processing systems and it does not require installation vessels with particularly large cranes or great lift capacity. At the installation site, the towable unit 32 can be lowered into a predetermined gap in the subsea production system in a ‘plug and play’ manner, whereupon the unit 32 may be connected via jumpers or spools at each towing head 28, 30 to other elements of the production system, which may be placed on the seabed before or after the unit 32.

(37) Reference is made to OTC 6430 for a more detailed description of the CDTM technique but a brief description follows in the context of the present invention. The CDTM principle involves the transportation of a prefabricated and fully-tested towable unit 32 suspended on towing lines 80 between two installation vessels 82, which may be tugs. A third vessel 84 may be employed for monitoring purposes as shown in FIG. 7a. An outer pipe surrounding the pipeline bundle 26 may be used to define a chamber to adjust buoyancy, or buoyancy may be adjusted by modules attached to the pipeline bundle 26. Chains 86 attached to the pipeline bundle 26 provide additional weight so that, at rest, the pipeline bundle 26 floats clear of the seabed 88 but beneath the influence of wave action near the surface 90.

(38) When the towable unit 32 reaches the installation location, it is lowered toward the seabed 88 by reducing its buoyancy, for example by flooding the outer pipe surrounding the pipeline bundle 26, while the towing lines 80 are paid out from the installation vessels 82. The towable unit 32 then settles on the seabed 88 as shown in FIG. 7b, whereupon tie-ins to prelaid elements 92 of the subsea production system can be made, for example using jumpers or spools (not shown) fitted with suitable known connectors.

(39) FIG. 8 shows in more detail how the towable unit 32 fits into a subsea production system 94. In this example, the subsea production system 94 comprises two templates 96 and three satellite wellheads 98. The templates 96 are supplied with power and chemicals from the downstream towhead 30 through primary umbilicals 100. Secondary umbilicals 102 supply power and chemicals from the templates 96 to the satellite wellheads 98. Such chemicals may be remediation fluids such as methanol or diesel oil that may be injected for maintenance purpose into the valves of a wellhead, after a shutdown, to remove wax where it may appear. The templates 96 are also supplied with water for injection from the manifold 40 of the upstream towhead 28 through water lines 104.

(40) Production flowlines 106 carry well fluids from the templates 96 and the satellite wellheads 98 back to the manifold 40 of the upstream towhead 28 for processing as described previously. The resulting wellstream then passes along the pipeline bundle 26 for wax control before passing through a spool 108 to a Pipeline End Module (PLEM) 110 for onward transport in a cold flow state.

(41) FIG. 9 shows a variant 112 of the upstream towhead 28 shown in FIG. 5. FIG. 10 shows that upstream towhead variant 112 in the context of a towable unit that also comprises a pipeline bundle 26 and a downstream towhead 30 as previously described.

(42) The upstream towhead variant 112 has an elongated frame 114 to encompass wellheads 116 or to provide a corresponding array of drilling slots. Again, the processing and flow-handling equipment is largely carried within the cross-section of the frame 114. However, some equipment may protrude from the frame 114, such as the wellhead equipment 118 seen protruding from the top of the frame 114 at its upstream end to the top right in FIG. 9. The open-topped structure of the frame 114 is beneficial in this respect; some such equipment 118 may be landed into the frame 114 after the upstream towhead variant 112 has been installed on the seabed.

(43) Moving on finally now to FIGS. 11 and 12 of the drawings, these show how the pipeline bundle 26 may be arranged to control wax formation. FIG. 12 shows the pipeline bundle 26 of the invention but to illustrate the general principle, FIG. 11 shows a prior art wax control system 120 which will be described first.

(44) The wax control system 120 of the prior art comprises long pipes 122 laid on the seabed, in this example three pipes, each of which is about 1.0 to 2.0 km in length. The pipes 122 are disposed in parallel about 10 to 20 m apart on the seabed but are connected in series by spools 124. Consequently, the wellstream flows in a first direction through a first pipe 122A, reverses direction in a first spool 124A, flows in the opposite direction through a second pipe 122B, reverses direction in a second spool 124B, and flows back in the first direction through a third pipe 122C before exiting the wax control system 120. Having therefore travelled between about 3.0 and 6.0 km in this example, the wellstream exits the wax control system 120 in a much-cooled state.

(45) The pipes 122 are each of pipe-in-pipe (PiP) construction to define annular jackets 126 around flowlines 128. To cool the wellstream in the flowlines 128, pumps 130 pump raw seawater into the jackets 126 from one end of the system 120, providing beneficial counterflow in the first and third pipes 122A, 122C if not in the second pipe 122B. This cools the wellstream enough to force wax to deposit on the inner walls of the flowlines 128.

(46) The wax deposits are removed periodically by localised heating when feedback sensors (not shown) indicate that the wax layer has reached a limiting thickness. Heating is achieved by heating cables 132 that extend along the outside of the flowlines 128 within the annular jackets 126; when powered by a power unit 134, the heating cables 132 cause the wax layer to melt off and become entrained in the wellstream.

(47) The wax control system 120 of the prior art would be of no use for the purposes of the present invention, where the pipeline bundle 26 is apt to be used as a tensile member in a towable unit 32, 114. In contrast, the pipeline bundle 26 of the invention shown in cross section in FIG. 12 comprises an outer pipe 136 that surrounds three PiP sections 138. The PiP sections 138 are joined in series and extend in parallel like the prior art shown in FIG. 11; there could be more or fewer of them. The outer pipe 136 protects, supports and retains the PiP sections 138 and also bears most or all of the tensile loads experienced by the pipeline bundle 26 during fabrication, towing and installation of the towable unit 32, 114.

(48) It will, of course, be understood that the cross-sectional view of FIG. 12 is simplified and omits details of coatings and linings as well as heating arrangements.

(49) Cooling and heating may be achieved in various ways, although an advantage of distributed water cooling pumps in both towheads 28, 30 is that beneficial counterflow of cooling water may be achieved in all of the PiP sections 138. There must be an expansion loop at each end of the multiphase flowline allowing for expansion in the region of 0.5 m.

(50) Each PiP section 138 is connected to a heating system 140 based on AC power from the power station 74 of the downstream towhead 30. The heating system 140 can be either a DEH (direct electrical heating) or a SECT (skin effect current tracing) system. The latter is currently preferred due to lower power requirements but this is not essential. Both heating techniques, and indeed others, will be known to the reader skilled in the art of subsea oil and gas engineering.

(51) As no intermediate processing stations such as pump systems need to be inserted into the pipeline bundle 26, this allows the bundle geometry to remain the same along its length to ease both fabrication and mechanical design.