WO2017010893A1

WO2017010893A1 - Transporting fluid from a well, in particular to a production header

Info

Publication number: WO2017010893A1
Application number: PCT/NO2016/050160
Authority: WO
Inventors: Jan Narve HAUGSTAD BAKKEN
Original assignee: Jb Services As
Priority date: 2015-07-15
Filing date: 2016-07-14
Publication date: 2017-01-19
Also published as: NO20180221A1; NO20150922A1

Abstract

There is described a method and related apparatus for transporting fluid from a well (3) and supplying the fluid into a production header (12). The fluid may be transported through a path (19) between the well and the production header. At least one pump (20) may be provided at a location along the path to drive the fluid along the path. The pump may be operated to apply a vacuum or partial vacuum in the path to allow the fluid to travel along the path from the well to supply the fluid to the production header, e.g. for starting up a well.

Description

TRANSPORTING FLUID FROM A WELL, IN PARTICULAR TO A PRODUCTION HEADER

Technical field

The present invention relates to apparatus for transporting fluid from a well, and related methods.

Background

In the oil and gas exploration and production industry, fluid produced from a production well is conventionally transported from the well through a flowline connected to a receiving facility.

The receiving facility may be equipped to service the well for example to provide an access point to the well, and/or to control the outflow of production fluid from the wellhead. In particular, in a field where multiple wells are present, production fluid from those wells may be led through respective flowlines to the receiving facility where the fluid is then combined. For this purpose, the receiving facility may typically be provided with a production header to which several flow lines carrying production fluid can be connected, such that the flowlines are gathered at the production header and the fluid from those lines can be combined. Each flowline connected to the header may link with a different well or set of wells in the field. In the case of an offshore well, the receiving facility may be a wellhead platform, and a flowline may take the form of a production riser extending between the seabed and the wellhead platform. From the receiving facility, the received fluid may be led into a longdistance transport pipeline, e.g. on the seabed, to transport the fluid to a processing facility located remotely from the receiving facility.

As will be appreciated, a production well typically has a wellbore which extends beneath the earth's surface to access hydrocarbon fluid in a reservoir, and under the pressure of the reservoir the hydrocarbon fluid may enter the wellbore, and travel upward through the wellbore to the surface. In this way, fluid containing hydrocarbons produced from the well can typically be transported from the well to the receiving facility by way of the well pressure, depending upon there being a sufficient pressure differential to drive the fluid in a flow to the receiving facility.

In a new well prior to production, or after a deliberate shutdown of a well from which hydrocarbons have previously been produced, the well can be in a "cold" condition where fluid that has collected in the wellbore may be poorly mixed, heavy and viscous and may possess a low tendency to flow. Over time, the fluid may collect in the well in a non-uniform column, stratified with water, oil, and gas components layered above one another.

In this "cold" condition, the pressure differential needed for producing the hydrocarbons may be absent such that a flow of fluid from the well to the receiving facility may not establish itself spontaneously. In such a case, in order to establish a flow from the well, standard practice is to use a well intervention technique whereby a tool is inserted into the well, e.g. on a wireline or the like, to help to stimulate flow. This may include inserting a tool such as a sucker rod into the wellbore, and pulling the rod upward in the well to lift the production fluid toward the surface. Fresh warm fluid from the reservoir may then flow into the base of the well and flow upward in the wellbore to the surface. Over time, the temperature in the wellbore and conditions can develop to "warm up" the well allowing fluid to be produced from the well in a self-sustaining flow with the necessary pressure differential established. Performing well intervention techniques of this kind above can be logistically complex, time consuming, and expensive. Indeed, the cost of well intervention can be prohibitive to starting- up the well, in particular if the well is of low priority, e.g. compared with other wells targeting the same reservoir region. If the well is nearing the end of its life, it may be considered uneconomic to try to start up such a well.

Another issue can be experienced where multiple wells are tied in to a production header, in that the pressure of the fluid required to deliver fluid from a given well into the header can be significant, and can depend upon the pressure in the fluid being produced via the header from the other wells. If the pressure required to deliver the fluid into the header is not achieved, the particular well in question may be abandoned as uneconomic due to the relative higher productivity of other wells tied to the header, despite in principle producing "good pressure" (i.e. a substantial pressure in the connecting line between the well head and the header, which might otherwise be sufficient in circumstances where other wells were not tied to the header). The pressure in the header may thus be experienced as a back pressure exerted on the well sought to be tied in, in effect preventing flow through the path between the well head and the production header. The back pressure from the header can act as an obstacle if a particular well connected to a production header is desired to be taken out of service temporarily, with a view to recommencing production from the well later. Similarly, it can exacerbate the challenges described above with regard to a "cold" startup, e.g. for the first time, and traditional interventional "startup" techniques may fall short also in these circumstances. Summary of the invention

in light of the above, according to a first aspect of the invention, there is provided a method of transporting fluid from a well and supplying the fluid into a production header, through a path between the well and the production header, the method comprising the steps of:

(a) providing at least one device at a location along the path to drive the fluid along the path; and

(b) operating said device to obtain at least one pressure condition in the path to allow the fluid to travel along the path from the well and supply the fluid to the production header.

The obtained pressure condition may comprise a vacuum or a partial vacuum produced upstream of said device.

The obtained pressure condition may comprise a pressure produced downstream of said device, wherein the produced pressure may be greater than a delivery pressure which may be required to deliver the fluid into the production header.

The device may comprise at least one pump which may comprise for example any one or more of: a vacuum pump; a liquid ring pump; a multiphase pump; a centrifugal pump. Typically, the device may comprise a liquid ring pump. The device may comprise at least one further pump. The method may further comprise operating the liquid ring pump to draw in the fluid from the well to deliver the fluid to the further pump. The method may further comprise operating the further pump to drive the delivered fluid downstream. By performing step b, a back pressure to which the well is exposed may be reduced, such that the fluid may be allowed to flow out of the well along the path. At a prior point in time, for example initially, the path may have a first back pressure. Fluid from the well in the path may then be subjected to the first back pressure which may prevent flow of the fluid in the path. Upon performing step b, the well, or fluid from the well in the path, may be exposed or subjected to a second back pressure, different to the first back pressure, and which may typically be lower than the first back pressure, such that the fluid can be allowed to flow out of the wed. The first back pressure may thus typically not allow, e.g. may be of too greater magnitude to allow, the fluid to flow along the path and into the header. Step b may be performed temporarily, e.g. when required. The step b may only be required for a certain period, e.g. until the well has "warmed" up. Afterwards, flow may be possible through the path and into the production header, without needing to operate the device as in step b. For example, the well pressure at the wellhead may be sufficient alone to drive the flow through the path without use of the device in step b.

Accordingly, the method may further include terminating operation of the device, and with the device terminated, the method may further include letting the fluid travel along the path from the well and into the production header.

Typically, the device may be remote from the well. The device may be positioned such that the distance along the path from the device to the production header is less than the distance to the well, e.g. to the well head. The path may extend upward between the well, e.g. the wellhead, and the production header through a riser. The device may be positioned at a location along a part of the path between an upper end of the riser and the production header.

Accordingly, the well may be an offshore well.

The production header and/or said device may typically be provided on a receiving facility, such as a wellhead platform, e.g. into which multiple production wells may be tied. The receiving facility may be positioned in proximity to the well. The receiving facility may be provided on a platform, e.g. at or above a surface of the Earth. The receiving facility may be configured to tie in a plurality of wells to combine the produced fluid from the wells in a common flow. The receiving facility may have a production header, through which multiple wells may be tied to combine the fluid. Accordingly, the fluid from the well may be combined at the header with fluid from multiple wells. The receiving facility may be adapted to allow access to the well or wells, and/or to control the production of fluid from the well. The well may be an offshore well. The receiving facility may typically comprise a wellhead platform or may be a vessel, which may be associated with one or more offshore wells. The device may be arranged to be operative to drive the fluid along the path in a part of the path between a test header and the production header.

The method may be applied to start up the well, e.g. in a cold start-up. According to a second aspect of the invention, there is provided apparatus for transporting fluid from a well and supplying the fluid into a production header, the apparatus comprising: a path between the well and the production header; and at least one device for driving the fluid along the path, the device being arranged to be operable to obtain at least one pressure condition in the path to allow the fluid to travel along the path from the well and supply the fluid into the production header. The device may comprise a pump arrangement configured to be operable to obtain said pressure condition. The pump arrangement may comprise first and second pumps, wherein the first pump may be arranged to pump the fluid to produce pumped fluid exceeding a minimum flow rate for acceptance of the fluid by the second pump. The second pump may be arranged to pump the pumped fluid produced by the first pump.

The first pump may typically comprise a vacuum pump configured to produce a vacuum or a partial vacuum in the path upstream of the pump, to allow the fluid to flow through the pump. The first pump may comprise a liquid ring pump. The second pump may comprise a multiphase pump.

The apparatus may further comprise at least one liquid supply for adding liquid to the fluid from the well for facilitating operation of either or both of the first and second pumps. The apparatus may further comprise a separator arranged to receive at least some of the pumped fluid from either or both of the first and second pumps. The separator may be arranged to allow liquid and gas in the received fluid to separate and may be further arranged to allow the separated liquid to be added to the fluid from the well to facilitate the operation of either or both of the first and second pumps.

The production header may typically be positioned on a platform, rig or other receiving facility. The fluid may typically comprise liquid and gas, and may typically include oil or gas recovered from a hydrocarbon reservoir. The fluid may thus comprise production fluid and may include for example gas, oil, water, or combinations thereof. Some solid material may also be contained in and carried with the fluid, in certain variants, the device may comprise a compressor.

According to a third aspect of the invention there is provided a method of starting up a well, whereupon fluid from the well is transported through a path between the well and a receiving facility, the method comprising the steps of:

(a) providing at least one device to drive the fluid along path; and (b) operating said device to obtain at least one pressure in the path that allows the fluid to travel along the path from the well to the receiving facility;

(c) terminating operation of said device after a period of time; and

(d) while terminated, letting the fluid flow out of the well and onward to the receiving facility.

According to a fourth aspect of the invention, there is provided apparatus for performing the method of the third aspect. The apparatus may be apparatus as set out in relation to the second aspect.

According to a fifth aspect of the invention, there is provided a method of transporting fluid from a well, the fluid being transported between the well and a receiving facility, the method comprising the steps of.

(a) providing at least one device to drive the fluid along a path between the well and the receiving facility; and

(b) operating said device such that a back pressure to which the fluid is subjected allows the fluid to travel along the path upstream of said device, and such mat a pressure is generated downstream of said device to drive the fluid to the receiving facility. According to a sixth aspect of the invention, there is provided apparatus for performing the method of the fifth aspect. The apparatus may be apparatus as set out in relation to the second aspect.

Any of the aspects of the invention may include further features as described in relation to any other aspect, wherever described herein. Features described in one embodiment may be combined in other embodiments. For example, a selected feature from a first embodiment that is compatible with the arrangement in a second embodiment may be employed, e.g. as an additional, alternative or optional feature, e.g. inserted or exchanged for a similar or like feature, in the second embodiment to perform (in the second embodiment) in the same or corresponding manner as it does in the first embodiment.

Embodiments of the invention can be advantageous in various ways as will be apparent from throughout the specification. Description

There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which: Figure 1 is a schematic representation of apparatus according to an embodiment of the invention;

Figure 2 is a schematic close-up representation of part of the apparatus of Figure 1;

and

Figure 3 is a schematic representation of apparatus according to another embodiment.

With reference to Figure 1, a receiving facility 10 is exemplified where production wells 1a-1d are connected to a production header 12 in the receiving facility 10. The production well 1d is shown in detail in Figure 1, and is connected to the production header 12 to allow fluid from the well 1d to pass into the production header 12 via an extraction path 19. The wells 1a-1d are connected to a common transport pipeline 8 through the production header 12, which in effect is a manifold allowing multiple wells to be joined together, such that the fluid produced from each of the wells 1a-1d, can flow into the production header 12 and be combined together in the transport pipeline 8 for onward transport.

In the example of Figure 1, the wells 1a-1c are productive, and extracted fluid from the wells 1a-1c flows through the manifold into the transport pipeline 8. Initially, the production well 1d may be non-productive in that the fluid from the well 1d is unable to flow into the production header 12 in view of the pressure P2 of fluid inside the header 12. In this way, the header 12 in effect provides a back pressure against flow into the header 12 along the extraction path 19. The pressure P1 at the top of the well 1d is substantial, but insufficient relative to the pressure P2 to generate flow into the header 12, the pressure P2 being associated with the production fluid from the wells 1a-1c at the production header 12.

As illustrated by Figure 1 , the fluid 2 includes water, oil and gas components which have naturally separated over time into successive layers in the well 1d, owing to differences in density. Gas has migrated in bubbles toward the upper end of the column of the fluid 2 in the well 1d.

In order to extract the fluid 2 from the well 1d, the receiving facility 10 is provided with apparatus in the form of a processor unit 20 arranged on the extraction path 19, downstream from the wellhead 3. In particular, the processor unit 20 is positioned between a test header 11 and the production header 12 in the receiving facility 10. An inlet 21 of the processor unit 20 is in pressure communication with the fluid 2 in the well 1d. The processor unit 20 operates to draw in fluid from the extraction path 19 so as to generate suction and a partial vacuum at the inlet 21. By operating the processor unit 20, gas from the extraction path 19 flows into the inlet 21 of the processor unit 20, and the pressure P1 on the upstream side of the processor unit 20 is reduced. A positive pressure differential in the fluid from the well between the well head 3 and the processor unit 20 (i.e. in the part of the path 19 upstream of the processor unit 20) is produced allowing fluid to flow along the path 19 downstream from the well 1d.

The processor unit 20 further operates to provide a pressure on a downstream side of the processor unit 20 for driving the fluid onward into the production header 12. The extraction path 19 is provided by a first flowline 4 which extends from the wellhead 3 to the test header 11 , the test header 11 , and a second flowline 14 which extends from the test header 11 to the processor unit 20. The inlet 21 of the processor unit 20 is in communication to receive fluid 2 from the wellbore of the well 1d (e.g. the bore of the production tubing installed therein) through the first flowline 4, the test header 11 , and the second flowline 14.

As the oil, gas and/or water of the fluid 2 is extracted from the well 1d, the fluid 2 in the well 1d is replenished with a fresh inflow from the hydrocarbon reservoir that then travels through the well 1d toward the surface under influence of the established pressure differential. A continuous flow of fluid extracted from the well is established in the extraction path 19. The processor unit 20 is run until the flow of the fluid 2 from the reservoir through the well 1d and into the production header 12 is sustainable, stable, and can keep going by itself without help from the processor unit 20. When this is achieved, the apparatus 20 may be taken out of operation. Accordingly, the processor unit 20 is particularly suited for use in the start-up phase of the well 1d, until the well has warmed-up, and can self-produce.

With further reference now to Figure 2, the processor unit 20 in this example includes a first pump in the form of a liquid ring pump 22 and a second pump in the form of a multiphase pump 24. An outlet of the liquid ring pump 22 is connected to an inlet of the multiphase pump 24 via a pipe section 23. The inlet of the liquid ring pump 22 is connected to the second flowline 14, such that the inlet is in communication with the wellbore of the well 1 d for receiving the fluid 2 therefrom. The liquid ring pump 22 is powered by a motor (not shown), and operates to draw, at least initially, gas from the well 1d along the extraction path 19, through the flowline 14, and into the inlet of the pump 24. As the gas is pulled from the extraction path 19 through the pump 22 and is pumped into the pipe section 23, the pressure upstream of the liquid ring pump 22 is reduced such that the fluid 2 can flow out of the well 1d. The pumped fluid from the liquid ring pump 22 has a relatively low flow rate in the pipe section 23, but it is sufficient for the pumped fluid to supply the multiphase pump 24. The multiphase pump 24 receives a flow of the pumped fluid from the liquid ring pump 22 and pumps this onward into the production header 12. After passing through the multiphase pump 24, the fluid being extracted from the well 1d is received at the production header 12 and combined with production fluid from the other wells 1a-1c in the common transport line 8 for transport downstream to a fluid processing facility, e.g. remote from the receiving facility 10, where the fluid may be separated and/or treated chemically and turned into an export product with pre-defined characteristics.

The multiphase pump 24 acts to build up the pressure in the fluid being produced from the well 1d so that the pressure [at the outlet of the pump 24, in the fluid on the downstream side of the pump] is sufficient for the fluid 2 from the well 1d to be inserted into and combined with the flow of fluid from the other wells 1a-1c in the header 12. The multiphase pump 24 outputs pumped fluid so that it obtains a greater flow rate and pressure than in the pipe section 23. In other variants, one or more further multiphase pumps 24 may be arranged in series to generate the necessary step-up in pressure for delivery of the pumped fluid into the production header 12. Typically, the pressure in the transport line 8 at the production header 12 may have a significant pressure which needs to be at least matched or overcome by the multiphase pump 24 in order to successfully deliver fluid 2 from the well 1 into the transport line. Typically, the liquid ring pump 22 alone is not able to deliver fluid at sufficient fluid flow rate and pressure into the transport line at the header 16. Typically also, the multiphase pump 24 alone requires a minimum supply of fluid at its inlet in order to operate and generate the required pressure and flow rate increase into the header 12. Therefore, the multiphase pump 24 alone cannot typically generate suction in an initial situation of "no flow" from the well 1d.

Accordingly, a key purpose of the liquid ring pump 22 in embodiments of the invention is to generate enough flow into the inlet of the multiphase pump 24 for the multiphase pump 24 to operate, so as to build up the pressure and flow rate further. It is found that this can be achieved by generating a vacuum or partial vacuum in the extraction path 19 using the liquid ring pump 22 whereby the fluid from the well 1d can begin to flow under well pressure. The fluid from the well 1 is received into the pump 22 and is output into the multiphase pump 24. The liquid ring pump 22 and the multiphase pump 24 continue to run cooperatively until the well is "warm" and a long-term self-sustaining flow is obtained from the well 1 into the production header 12. The path from the well 1d upstream of the liquid ring pump 22 tends to contain gas, especially after a well 1d has been shut down or is cold such that a natural separation of constituents has occurred and a column of gas of substantial height is present at the top of the well 1d. As such, the liquid ring pump 22 is well suited to receive and act on the gas to generate suction and reduce the pressure between the well and the liquid ring pump 22.

The liquid ring pump 22 requires some liquid in order to maintain an annular liquid ring inside a housing of the liquid ring pump 22. If sufficient liquid is not present in the fluid from the well 1d, liquid for maintaining the ring can be supplied into the fluid from the well near the inlet of the liquid ring pump 22. To this end, the processor unit 20 exemplified includes a tank 30 for storing liquid, from which an amount of liquid can be supplied into the flow line 14 upstream of the pump through a first supply line 31. A first supply pump 33 is used to pump liquid from the tank 30 into the flowline 1 of the extraction path 19. Liquid from the tank 30 can also be supplied into the pumped fluid from the liquid ring pump 22 so as to ensure that an appropriate amount of liquid is present also for operation of the multiphase pump 24. As can be seen in Figure 2, the processor unit 20 includes a second supply line 32 through which liquid from the tank 30 can be fed into the pumped fluid in the pipe section 23. The processor unit 20 includes a second supply pump 34 for pumping liquid from the tank 30 into the pipe section 23.

The first and second supply pumps 33, 34 are controlled by a controller 40 which is arranged to communicate with the first and second supply pumps 33, 34. The controller 40 may include a computer device and may be arranged to send data to the first and/or second supply pumps 33, 34 to operate them appropriately, e.g. to supply suitable amount of liquid into the flowline 14 or the pipe section 23. The controller 40 may also be arranged to communicate with the liquid ring pump 22 and the multiphase pump 24 for obtaining status information. The controller 40 is also arranged to communicate with the tank 30, for example to control valves on the tank 30, or to obtain tank information such as liquid levels, etc. Instructions may be communicated by the controller 40 to the tank 30, and/or to the first and/or second supply pumps 33, 34, based upon the obtained tank information and/or the pump status information.

Once fluid is extracted from the well 1d using the liquid ring pump 22 and the multiphase pump 24 over a period of time, and a continuous self-sustaining flow has been established, the pumps may be taken out of operation. The conditions of the well 1d and of the fluid 2 exiting the well may then be quite different, and may allow the fluid 2 to be extracted naturally. For example, the fluid may be better mixed and/or less viscous such that energy dissipation through friction in the well is less. Accordingly, the pressure P1 arising in the fluid 2 at the top of the well 1d may be suitable for driving the fluid into the production header 12 directly, without requiring the additional impetus of reducing the pressure in the extraction path 19 to encourage the fluid to flow out of the well 1d from the well head, or building the pressure up again along the extraction path 19 by means of the multiphase pump 24.

Turning now to Figure 3, an alternative processor unit 120 is exemplified, configured to be provided on the production facility 10 in place of the above-described processor unit 20, where appropriate.

In this example, the processor unit 120 includes a first, liquid ring pump 122 and a second, multiphase pump 124 arranged in series. In addition, a separator 130 is provided. The fluid 2 from the well 1d is drawn from the extraction path 19 into the liquid ring pump 122 to obtain a vacuum or partial vacuum in the extraction path 19 at the inlet of the liquid ring pump 122. The liquid ring pump 122 pumps the fluid 2 from the well 1d into the pipe section 123, and the multiphase pump 124 pumps the pumped fluid from the liquid ring pump 122 into a pipe section 116. The fluid from the well which is pumped out of the multiphase pump 124 is supplied into the separator 130, and is then supplied onward from the separator 130 to the production header 112 via an output pipe section 117 of the processor unit 120. In this example therefore, the fluid 2 from the well 1d is subjected to an extra processing step in the separator 130 before reaching the production header 12.

In the separator 130, the fluid which is output from the multiphase pump collects and stratifies under gravity, according to their differences in density. Thus, liquid constituents such as water and oil are overlain by gas.

An amount of the collected liquid from the separator 130 is supplied back into the liquid ring pump 122, if required, in order to ensure that the liquid ring pump 122 receives sufficient liquid to operate effectively, e.g. when not enough liquid is present in the fluid 2 from the well 1. The liquid from the separator 130 is supplied to the liquid ring pump 122 via a first supply line 131, using a first control valve 133 to control the amount of liquid that enters back into the liquid ring pump 122. Similarly, the multiphase pump 124 is supplied with an amount of liquid from the separator 130, if required, so that the multiphase pump 124 processes the fluid from the liquid ring pump 122 with a suitable amount of liquid present. The liquid is supplied to the multiphase pump 124 from the separator 130 via a second supply line 132, using a second control valve 134 to control the amount of liquid entering the multiphase pump 124.

The supply of liquid to the liquid ring pump 122 and the multiphase pump 124 is controlled using a controller 140. The controller 140 is arranged to communicate with the first and second valves 133, 134, and may send data to the first and/or second valves 133, 134 to adjust them accordingly, e.g. to supply suitable amount of liquid to the liquid ring pump 122 and/or multiphase pump 124. The controller 140 may also be arranged to communicate with the liquid ring pump 122 and the multiphase pump 124. The controller 140 may provide instructions for operating the pumps 122, 124, and may receive status information from the pumps e.g. regarding the amount of liquid in the fluid which they are processing. Based upon the status information, the controller may send an instruction to first and/or second valves 133, 134 for supplying liquid suitably. The controller 140 is also arranged to communicate with the separator 130, for example to obtain separator information such as liquid levels etc. Instructions may be communicated by the controller to the separator 130, and/or the first and second valves 133, 134, based upon the obtained separator information and/or pump status information.

By way of the separator 130 in the processor unit 120, liquid contained in the fluid 2 from the well 1d may be recirculated and utilized to maintain liquid levels in the liquid ring pump 122 and the multiphase pump 124. If the fluid 2 from the well 1d does not contain much liquid, this may be useful, to maximize the liquid available to maintain operation of the pumps 122, 124, and to reduce capacity requirements in the separator tank 130. The need for adding liquid into the system e.g. through a supply tank, may therefore be reduced. It can be noted that an outlet 135 for the fluid collected in the separator 130 may be provided at an elevated level so that liquid only leaves the separator 130 if that level is reached. If not, the liquid is stored in the base of the separator 130, and utilized.

As an example of how the processor units 20, 120 can operate, a typical scenario can be that there is initially an insufficient differential between the pressure at the wellhead 3 and the production header 12 for flow to occur. The pressure P1 at the top of the well, in the path between the well and the production header, and at the production header is then in the range of around 10-15 bar. The pumps 22, 122, 24, 124 in the extraction path 19, 119 are then operated to generate suction and reduce the pressure in the path 19, 119 upstream of the liquid ring pump 22, 122. The liquid ring pump 22, 122 acts to bring the pressure in the fluid upstream of the liquid ring pump 22, 122 down to an absolute pressure of around 0.2 bar (gauge pressure of approximately -0.8 bar). Using a typical liquid ring pump 22, this can result in a flow rate of up to around 12 m³ hour and an absolute pressure of 1.8 bar (gauge pressure of approximately 0.8 bar) in the pipe section 23, 123, at the inlet to the multiphase pump 24,124. The multiphase pump 24, 124 may be configured to step the pressure up from an absolute pressure of around 0.4 bar at the inlet to an absolute pressure of around 40 bar and a flow rate of around 120 m³/hour at the outlet, in the fluid downstream from the multiphase pump 24, 124. In this condition, the fluid output from the multiphase pump 24, 124 can enter the test header 11 and can be successfully led into a transport pipe 8 to combine with production fluid from the other wells 1 a-1 c.

In general, the pressure may be built up downstream from the liquid ring pump 22, 122 to a specific pressure using one or more multiphase pumps. The multiphase pump 24, 124 has an "overcapacity" with respect to the liquid ring pump 22, 122, whereby the pump 24, 124 can readily accept the flow of fluid pumped from the liquid ring pump 22, 122 without generating resistance or a backpressure buildup that hinders the flow into the multiphase pump 24, 124. The back pressure to which the fluid at the well head 3 is subjected is lower when operating the pumps in the processor units 20, 120, than that initially experienced when the pumps are not operational. The operation of the pumps in the processor units 20, 120 opens up a positive pressure differential between the well head 3 and the pumps, on the upstream, "suction side", of the pumps, so that flow into the processor units 20, 120 occurs.

By way of the present technique a flow of production fluid can be obtained without performing well intervention, simply by applying the processor unit 20, 120 on the receiving facility 10 to reduce the pressure at the top of a well. Typically, the receiving facility is a topsides tie-in facility for connecting multiple wells at the production header. The receiving facility 10 may be a wellhead site, or a wellhead platform in the case of an offshore well. Use of a processor unit 20, 120 on such a facility can be convenient and cost effective compared with traditional well intervention techniques. Equipment does not need to be inserted into the well 1d in order to stimulate and or start up the well. Production from wells which otherwise may be abandoned or de-prioritized may be achievable, and the recoverability of hydrocarbons from a reservoir may increase.

Various modifications and improvements may be made without departing from the scope of the invention herein described. While a liquid suction pump 22, in particular, has been described in the foregoing, it will be appreciated that other pumps which may generate flow by generating a vacuum or partial vacuum and which do not require any substantial supply of fluid into the inlet of the pump may be used instead. For example, a compressor may be employed to lower the pressure to generate flow and feeding the multiphase pump 24, 124. The compressor may be a wet gas compressor so as to be able to handle a certain amount of liquid within the gas. The flowline 4 may comprise a riser between the wellhead and the receiving facility. Thus, the processor units 20, 120 may operate as described in the above, to apply suction in the riser.

Claims

1. A method of transporting fluid from a well and supplying the fluid into a production header, through a path between the well and the production header, the method comprising the steps of:

(b) operating said device to obtain at least one pressure condition in the path to allow the fluid to travel along the path from the well to supply the fluid to the production header.

2. A method as claimed in claim 1, wherein the obtained pressure condition includes a vacuum or a partial vacuum produced upstream of said device.

3. A method as claimed in claim 1 or 2, wherein the obtained pressure condition includes a pressure produced downstream of said device, the generated pressure being greater than a delivery pressure required to deliver the fluid into the production header.

4. A method as claimed in any preceding claim, wherein the device comprises at least one liquid ring pump and at least one further pump, and the method further comprises operating the liquid ring pump to draw in the fluid from the well to deliver the fluid to the further pump; and operating the further pump to drive the delivered fluid downstream.

5. A method as claimed in any preceding claim, wherein by performing step b, a back pressure to which the well is exposed is reduced, such that the fluid is allowed to flow out of the well along the path.

6. A method as claimed in any preceding claim, wherein initially the path has a first back pressure, and upon performing step b, the well is exposed to a second back pressure which is lower than the first back pressure, such that the fluid is allowed to flow out of the well.

7. A method as claimed in claim 6, wherein the first back pressure does not allow fluid to flow along the path and into the header.

8. A method as claimed in any preceding claim, wherein step b is performed temporarily.

9. A method as claimed in claim 8, which further includes terminating operation of the device, and with the device terminated, letting the fluid travel along the path from the well and into the production header, while the operation of the device is terminated.

10. A method as claimed in any preceding claim, wherein the device Is remote from the well.

11. A method as claimed in any preceding claim, wherein device is positioned such that the distance along the path from the device to the production header is less than the distance to the well.

12. A method as claimed in any preceding claim, wherein the path extends upward between the well and the production header through a riser, wherein the device is positioned at a location along a part of the path between an upper end of the riser and the production header.

13. A method as claimed in any preceding claim, wherein the production header and said device is provided on a wellhead platform.

14. A method as claimed in any preceding claim, wherein the device is arranged to be operative to drive the fluid along the path in a part of the path between a test header and the production header.

15. Apparatus for transporting fluid from a well and supplying the fluid into a production header, the apparatus comprising:

a path between the well and the production header; and

at least one device for driving the fluid along the path, the device being arranged to be operable to obtain at least one pressure condition in the path to allow the fluid to travel along the path from the well and supply the fluid into the production header.

16. Apparatus as claimed in claim 15, wherein the device comprises a pump arrangement configured to be operable to obtain said pressure condition.

17. Apparatus as claimed in claim 16, wherein the pump arrangement comprises first and second pumps, wherein the first pump is arranged to pump the fluid to produce pumped fluid exceeding a minimum flow rate for acceptance of the fluid by the second pump, the second pump being arranged to pump the pumped fluid produced by the first pump.

18. Apparatus as claimed in claim 17, wherein the first pump comprises a vacuum pump configured to produce a vacuum or a partial vacuum in the path upstream of the pump, to allow the fluid to flow through the pump.

19. Apparatus as claimed in claim 17 or 18, wherein the first pump comprises a liquid ring pump.

20. Apparatus as claimed in any of claims 17 to 19, wherein the second pump comprises a multiphase pump.

21. Apparatus as claimed in any of claims 17 to 20, further comprising at least one liquid supply for adding liquid to the fluid from the well for facilitating operation of either or both of the first and second pumps.

22. Apparatus as claimed in claim 21 further comprising a separator arranged to receive at least some of the pumped fluid from either or both of the first and second pumps, the separator being arranged to allow liquid and gas in the received fluid to separate and further arranged to allow the separated liquid to be added to the fluid from the well to facilitate the operation of either or both of the first and second pumps.

23. A method of starting up a well, whereupon fluid from the well is transported through a path between the well and a receiving facility, the method comprising the steps of:

(a) providing at least one device to drive the fluid along path; and

(b) operating said device to obtain at least one pressure in the path that allows the fluid to travel along the path from the well to the receiving facility;

(c) terminating operation of said device after a period of time; and

24. Apparatus for performing the method of claim 23.

25. A method of transporting fluid from a well, the fluid being transported between the well and a receiving facility, the method comprising the steps of:

(a) providing at least one device to drive the fluid along a path between the well and the receiving facility; and (b) operating said device such that a back pressure to which the fluid is subjected allows the fluid to travel along the path upstream of said device, and such that a pressure is generated downstream of said device to drive the fluid to the receiving facility.

Apparatus for performing the method of claim 25.