Subsea well production flow system

Methods and apparatus for flowing a subsea well. The method comprises the steps of: supplying a multi-phase medium from a subsea tree 18 to a removable separator package 10; separating the multi-phase flow into one or more phases at the desired pressures, the pressures being controlled by one or more pressure control devices 51, 67, 71, 75, 76, 77, 78, 79 on one or more outlets from the separator package 10; and analysing each of the one or more phases to determine the amount and quality of products produced by the well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to European Patent Application No. 0.3256021.1, which was filed Sep. 24, 2003, and is titled “Subsea Well Production Flow System”, and is related to U.S. application Ser. No. 10/940,140 filed Sep. 14, 2004, now U.S. Pat. No. 7,134,498, and U.S. application Ser. No. 10/510,554 filed Oct. 7, 2004.

Not Applicable.

BACKGROUND

This invention relates to a subsea well production flow system and to a method of production testing and recording downhole characteristics in a subsea well. In particular, the invention relates to a method and system which assist in the determination of the quality and amount of products, such as gaseous or liquid hydrocarbons, produced by the well while at the same time logging the well to identify the rate of flow over the producing formation sections.

When a new production well is drilled and completed, it is necessary to flow test the well to evaluate its performance and flow characteristics from different intervals of the well. In an existing field, the well can be connected to the field seabed infrastructure and flowed back individually along the field's dedicated test line to the surface production installation on the surface installation, the well fluids can be separated and analysed for, amongst other things, flow rate, density and composition while at the same time carrying out a well intervention to monitor the downhole characteristics using a separate intervention vessel.

There are numerous disadvantages to this approach. Firstly, the subsea field infrastructure requires an individual and separate test line. Secondly, the new production well must be close to a field connection point and subsequently has to be connected to that connection point. Thirdly, the well must have sufficient energy to supply the fluid to the surface for the analysis to be carried out. Fourthly, a separate operation is required to access the well.

Other situations in which it is advantageous to flow test a well are on exploration wells, appraisal wells or early development wells to evaluate the production capabilities prior to installation of the flow lines or for production wells where there are no means to flow the well individually. All of these may be situations in which there is no field into which the fluid can be supplied. Currently, in order to flow test any of the above wells, it is necessary to provide either a drilling vessel or a work over vessel, together with a riser system in which the fluids from the well can be delivered to the surface, where they can be processed by a portable test separator on the deck of the respective vessels.

The disadvantages of the known arrangements are that the well must have sufficient energy to flow to the surface and, as a significant number of wells will not flow naturally to the surface, these cannot be tested.

Typically, the duration of a flow test depends upon the required degree of investigation, but last for at least two to three days, but could be for as long as several months. Quite clearly, the longer the flow test is carried out for, the better the fields reservoir performance can be estimated, but this can, of course, be extremely costly.

For a long test, a surface vessel is required which is expensive, time consuming and entirely dependent on having suitable weather conditions on the surface for the duration of the test. The key factor is to monitor the draw down of the reservoir by continuously flowing the well, and preferably to use continuous monitoring equipment suspended in the well or by carrying our periodic well production logging operations.

SUMMARY OF THE PREFERRED EMBODIMENTS

According to the present invention, there is provided a method of production flowing a subsea well, the method comprising the steps of: supplying a multi-phase medium from a subsea tree to a removable separator package; separating the multi-phase flow into one or more phases at the desired pressures, the pressures being controlled by one or more pressure control devices on one or more outlets from the separator package; and analysing each of the one or more phases to determine the amount and quality of products produced by the well.

In this way, the present invention allows the individual phases within the fluids produced by a well to be continuously tested and analysed either subsea or at the surface when a vessel is on the well.

When there is sufficient field infrastructure in place to connect the well production test system to, it will allow the well bore surface intervention vessel to depart and possibly return at periodic periods over the production test duration if monitoring equipment is not installed in the well. Alternatively, it could remain in place as an early production system.

For subsea this avoids the need for a continuous surface intervention installation which, as described above, are costly, complex and not always suitable for all fields.

Preferably, the multi-phase flow is separated by passing the flow into a toroidal separator. Such a toroidal separator provides a suitable separator which can be mounted in a subsea separator package, such that the fluids can piped individually to the surface, or can be commingled into either a rigid riser, flexible riser, or one or more flow lines. If the well does not have sufficient drive on its own to the seabed, artificial lift, such as gas lift, can assist the well to deliver the multi phase fluid to the production flow test system.

By providing pressure control devices on the outlets from the separator package, the separator can be operated at below ambient seawater pressure, or below the well fluid's hydrostatic pressure at the seabed, but will therefore require one or more pumps to carry the individual phases to the surface. This will allow a greater range of separation and a more detailed analysis of the performance of the well. Additionally, being able to lower the pressure considerably below the seawater ambient pressure, or below the well fluid's hydrostatic pressure at the seabed, will quickly allow the well to be brought on for a well that has insufficient energy. For low pressure wells this could be a process which can sometimes take several days, especially if the well has previously been killed by bullheading prior to a workover.

The present invention also provides a system for use in flow testing a subsea well, the system comprising: a subsea tree for, in use, connection to a wellhead; a separator package in fluid communication with a fluid take off from the subsea tree, such that, in use, a multi-phase medium can flow from the subsea tree into the separator for separation into one or more phases; and a pressure control device on each of one or more outlets from the separator package for allowing the system to be operated at different wellhead pressures.

The separator package may be located adjacent the subsea tree or, alternatively, may be mounted above the tree, to allow vertical access through the separator package and into the subsea tree.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1shows the present invention in a stacked configuration with vertical bore access to a surface vessel using an intervention riser. An advantage of using an intervention riser is that it can operate above the maximum well operations pressure. A separator package10, including a toroidal separator11, and associated spiral conduits12,13, are mounted around a spool body14, having a bore extending from the surface (not shown), through an intervention riser16, and an emergency disconnect package17, spool body14, the separator package, and into a spool tree18and, ultimately, into a subsea well. The well is provided, at its upper end, with a wellhead assembly20and is connected to the spool tree18.

The spool body14is provided with numerous rams including coil tubing gripping rams21, lower rams22and upper shear/blind rams23. The lower rams22may be coil tubing, cable or wire line rams. The shear/blind rams are designed such that, when operated, they can cut through the coil tubing9logging cable or wire line within the riser and provide a single pressure mechanical isolating barrier between the pressurised production fluid and the surface. An annular24and a stripping annular30are provided above the rams and upper25and lower26production barrier valves are located respectively above and below the rams.

This configuration allows the surface intervention vessel to run downhole monitoring equipment and to log the well, yet in an emergency can seal, cut, shut down the vertical flow and disconnect the intervention riser.

A production fluid take-off29from the bore15passes through a multi-phase valve27and a multi-phase choke28into the main bore40of the separator11.

FIG. 2shows a toroidal separator11having a main bore40which is provided with exit lines41and42for heavier and lighter fluids respectively. The exit line41is tangential to the bottom circumference of the bore40and is mounted on the lower outer portion of the bore. The exit line42for lighter fluids is mounted tangentially to the upper inner portion of the bore40. The location of the outlet is, of course, dependent on the actual flow which is expected to pass around the bore and therefore the location of the connections of the exit lines can be changed without effecting the operation of the invention.

The separator11is divided into a number of different interlinking areas, a gas stabilization section43, a gas toroidal44, a liquid toroidal section45, a liquid stabilizing section46, an oil separation section47and a solids removal section48. The usual medium would comprise a combination of sand and other solids, gaseous or liquid hydrocarbons, and water. In this example, the multi-phase flow production enters the main bore40through inlet49and is separated into wet gas, that is mainly gas but with entrained liquid, which exits through exit line42, and solids, liquid hydrocarbons such as oil, water and a little entrained gas which exit the bore40through exit line41.

The wet gas travels upwardly through the gas spiral toroidal44and a spiral conduit50, with the pressure/flow rate controlled by a choke51which is on the downstream side of gas sensors52and a gas isolation valve53. The liquid within the wet gas is forced into the outer wall of the gas toroidal44and the conduit50and collects. At certain points in the outer wall of the toroidal44and conduit50, liquid drain pipes54are provided to direct any liquid which has been separated from the gas flow back into a liquid toroidal60. The multi-phase liquid having trapped gas, which exits through exit line41, passes, via a liquid toroidal60, into the liquid stabilization section46, which is the upper portion of a spiral conduit61. As the liquid spirals down the conduit, any entrained gas is separated to the inner upper portion of the conduit and is separated off via exit lines62and is directed into the gas toroidal44. As the fluid passes further down through the conduit, and the gas is removed, it is the oil which moves to the upper inner portion and this is separated off via exit lines63into a common pathway64, which subsequently passes, via oil sensors65and an oil isolation valve66through an oil choke67.

At the lowermost end of the spiral conduit61, the sand/solids slurry, containing some residual liquid and any sand or solids entrained in the flow, pass out of the spiral conduit via a solid slurry line68, past a solids sensor69, a solids isolation valve70and through a solids choke71. The remaining water is channeled through a water exit line72past water sensors73, a water isolation valve74and through the water choke75.

FIG. 1shows a vertical well production test configuration to a surface vessel being either a drilling vessel or a dedicated intervention well test vessel. This configuration can be installed using a intervention riser16capable of containing the maximum well operating pressure by using a drilling vessel or a well test/intervention vessel.

Each of the exit lines from the separator II for gas, oil, water and solids is connected to a respective pump76,77,78,79for delivering the separated phases to the surface depending on the separator operating pressure. The choke line80can be connected to the gas pump76to deliver the separated gas to the surface. The outlets from the water78and solids79pumps are joined to deliver the water/solids, via the intervention riser line81to the surface. The separated oil is delivered via oil supply line82back into the bore15, above the upper production barrier valve25, for delivery to the surface.

If higher levels of separation are required, the separated phases can be admitted for further separation using a second or third separator. Alternatively, additional tubular bores can be provided as part of one or each exit line, thereby providing additional separation before the spiral conduits.

In a preferred example a booster line83on the intervention16is used to provide drive fluid to power the pumps, with exhaust drive fluid returning up the riser line84, although the pumps could, alternatively, be powered electrically.

FIG. 3shows a configuration that can be deployed by a drilling vessel using a heavy low pressure drilling riser89that does not require a dedicated intervention riser16.

The riser which is attached to the emergency disconnection package17is a low pressure drilling riser89and, as such, the drive fluid can be exhausted back into the main drilling riser, rather than requiring a separate line, with the coil tubing, cable or wire line9, as well as the separated oil, passing through a tubular pipe88within the riser.

The tubular pipe88can be drill pipe, tubing or casing of a suitable diameter and capable of containing above the maximum well bore pressure. The production test system can be run and connected up using the drilling riser89. The drilling vessel can then run and lock the tubular pipe into the body of the emergency disconnect package connector87to achieve full well access.

Once the fluids are on the surface vessel, they are handled in the same manner as a surface flow test albeit at a reduced pressure.

The riser lines80,81,83and84are shown as part of the riser but could equally be flexible lines hung from the surface vessel and connected to the emergency disconnect package17.

Using a field support vessel with lifting capability, the test module can be positioned adjacent the tree and connected up, either in the stacked configuration inFIGS. 2 and 3or alternatively and as shown inFIGS. 4 and 5in a side-by-side arrangement. The appropriate flow lines can connect the test module to the field manifold such that, once installed and flowing, the field support vessel can depart.

FIGS. 4 and 5show side-by-side configurations, with the separator package10, emergency disconnect17and riser16mounted on a firm base, such as a pile100, within the sea bed and connected to a spool tree, in this case, a conventional spool tree18or any type of subsea production tree via a bridging line101, through which all the necessary fluids can be caused to flow in individual lines. In this arrangement, there is, clearly, no direct vertical access to the well. The riser can be removed as it merely provides the means for getting the necessary fluids to the production test vessel and, subsequently, passing the separated phases from the multi-phase medium back to the surface. This can, of course, be done via additional pipe lines bundles110which connect into the main field, via a manifold (not shown). Such an arrangement is shown inFIG. 5. This configuration allows direct vertical well intervention to the spool tree18or other type of subsea production tree independent of the well processing operation.

The separator package10inFIG. 5could also be used in theFIG. 1configuration directly connected to the spool tree18. This allows the system to flow to a subsea field system or using a flexible bundle instead of a rigid bundle110to the surface being either the drilling rig or intervent vessel or a separate production flow test vessel and allowing the surface vessel to depart. The main purpose of this is to flow test the system which is independent of the subsea tree.

Two examples of spool trees which can be utilized in the arrangement inFIG. 1,2or3are shown inFIGS. 6A and 6B.FIG. 6Arepresents an external cap flow test spool tree andFIG. 6Bshows an internal cap flow test spool tree.

To prevent the requirements to remotely connect flow lines from the spool tree18to the separator10, to achieve vertical flow, two variations of the spool tree are suggested. This will enable the spool tree to provide double mechanical isolation barriers to the well flow.

A spool tree18is connected and sealed to a well head20comprising of a connector121and a spool body122. A orientated tubing hanger123is supported at a precise elevation in the spool body122. A lateral production port124provides a path for the well fluid to flow to a production master valve125, then through a production isolation valve126, and into a pipeline (not shown).

In the main vertical bore of the tubing hanger123, above the lateral port124, are two independent closure members130,131. The tubing hanger is provided with its own mechanical locking system to the spool body132and above is a second mechanical lock system133providing a dual independent lockdown system.

Below the tubing hanger123from the annulus, between the tubing19and the spool body122, a lateral port140connects to an annulus master valve141, an annulus isolation valve142and to an annulus pipeline (not shown). A crossover line with a crossover valve144provides a fluid path between the annulus and production pipework. An annulus workover path with an annulus workover valve145communicates with the spool body bore150below the top of the spool body122. A production port151communicates with the spool body bore150between the workover port146and the top of the tubing hanger123.

FIG. 6ashows a external tree cap160with a external connector161connecting and sealing to the hub profile of the spool body122. Monitoring and venting ports are provided to access the workover port146and the production port151. The tree cap160provides a total seal to the spool body bore150and a internal cap seal164prevents fluid communication between workover port146and production port151.

InFIG. 1, the separator10has a connector with a internal arrangement similar to the tree cap160that allows vertical independent production and annulus communication between the spool tree18and the separator10.

FIG. 6bshows the use of a internal tree cap170that locks and seals to the internal bore of the spool body122. The internal tree cap170has a production/annulus isolation seal between the production port151and the annulus port146.

In this arrangement, the spool tree will provide double mechanical pressure isolation of the well bore with or without the tree caps160,170in place and when the separator10is connected.

When direct well access is required, the closure members130,131have to be opened or removed and the valve and ram barriers in the separator10will become the prime isolation barriers.