Abstract:
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.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]     This application claims priority to European Patent Application No. 03256021.1, which was filed Sep. 24, 2003, and is titled “Subsea Well Production Flow System.” 
       STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT  
       [0002]     Not Applicable.  
       BACKGROUND  
       [0003]     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.  
         [0004]     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&#39;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.  
         [0005]     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.  
         [0006]     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.  
         [0007]     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.  
         [0008]     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.  
         [0009]     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  
       [0010]     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.  
         [0011]     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.  
         [0012]     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.  
         [0013]     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.  
         [0014]     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.  
         [0015]     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&#39;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&#39;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.  
         [0016]     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.  
         [0017]     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. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0018]     Examples of the present invention will now be described with reference to the accompanying drawings, in which:  
         [0019]      FIG. 1  shows a schematic side view of a stacked configuration of the present invention with an intervention riser;  
         [0020]      FIG. 2  shows a schematic toroidal separator suitable for use in the present invention;  
         [0021]      FIG. 3  is a schematic side view of the stacked configuration using a low pressure drilling riser and a maximum well operating pressure internal riser;  
         [0022]      FIG. 4  shows the present invention in a side-by-side arrangement but flowing up a intervention riser;  
         [0023]      FIG. 5  shows a further example of a side-by-side arrangement flow into a pipeline bundle; and  
         [0024]      FIGS. 6A and 6B  show external and internal caps for a spool tree for use in the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0025]      FIG. 1  shows 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 rise is that it can operate above the maximum well operations pressure. A separator package  10 , including a toroidal separator  11 , and associated spiral conduits  12 ,  13 , are mounted around a spool body  14 , having a bore extending from the surface (not shown), through an intervention riser  16 , and an emergency disconnect package  17 , spool body  14 , the separator package, and into a spool tree  18  and, ultimately, into a subsea well. The well is provided, at its upper end, with a wellhead assembly  20  and is connected to the spool tree  18 .  
         [0026]     The spool body  14  is provided with numerous rams including coil tubing gripping rams  21 , lower rams  22  and upper shear/blind rams  23 . The lower rams  22  may be coil tubing, cable or wire line rams. The shear/blind rams are designed such that, when operated, they can cut through the coil tubing  9  logging cable or wire line within the riser and provide a single pressure mechanical isolating barrier between the pressurised production fluid and the surface. An annular  24  and a stripping annular  30  are provided above the rams and upper  25  and lower  26  production barrier valves are located respectively above and below the rams.  
         [0027]     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.  
         [0028]     A production fluid take-off  29  from the bore  15  passes through a multi-phase valve  27  and a multi-phase choke  28  into the main bore  40  of the separator  11 .  
         [0029]      FIG. 2  shows a toroidal separator  11  having a main bore  40  which is provided with exit lines  41  and  42  for heavier and lighter fluids respectively. The exit line  41  is tangential to the bottom circumference of the bore  40  and is mounted on the lower outer portion of the bore. The exit line  42  for lighter fluids is mounted tangentially to the upper inner portion of the bore  40 . 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.  
         [0030]     The separator  11  is divided into a number of different interlinking areas, a gas stabilisation section  43 , a gas toroidal  44 , a liquid toroidal section  45 , a liquid stabilising section  46 , an oil separation section  47  and a solids removal section  48 . 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 bore  40  through inlet  49  and is separated into wet gas, that is mainly gas but with entrained liquid, which exits through exit line  42 , and solids, liquid hydrocarbons such as oil, water and a little entrained gas which exit the bore  40  through exit line  41 .  
         [0031]     The wet gas travels upwardly through the gas spiral toroidal  44  and a spiral conduit  50 , with the pressure/flow rate controlled by a choke  51  which is on the downstream side of gas sensors  52  and a gas isolation valve  53 . The liquid within the wet gas is forced into the outer wall of the gas toroidal  44  and the conduit  50  and collects. At certain points in the outer wall of the toroidal  44  and conduit  50 , liquid drain pipes  54  are provided to direct any liquid which has been separated from the gas flow back into a liquid toroidal  60 . The multi-phase liquid having trapped gas, which exits through exit line  41 , passes, via a liquid toroidal  60 , into the liquid stabilisation section  46 , which is the upper portion of a spiral conduit  61 . 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 lines  62  and is directed into the gas toroidal  44 . 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 lines  63  into a common pathway  64 , which subsequently passes, via oil sensors  65  and an oil isolation valve  66  through an oil choke  67 .  
         [0032]     At the lowermost end of the spiral conduit  61 , 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 line  68 , past a solids sensor  69 , a solids isolation valve  70  and through a solids choke  71 . The remaining water is channelled through a water exit line  72  past water sensors  73 , a water isolation valve  74  and through the water choke  75 .  
         [0033]      FIG. 1  shows 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 riser  16  capable of containing the maximum well operating pressure by using a drilling vessel or a well test/intervention vessel.  
         [0034]     Each of the exit lines from the separator II for gas, oil, water and solids is connected to a respective pump  76 ,  77 ,  78 ,  79  for delivering the separated phases to the surface depending on the separator operating pressure. The choke line  80  can be connected to the gas pump  76  to deliver the separated gas to the surface. The outlets from the water  78  and solids  79  pumps are joined to deliver the water/solids, via the intervention riser line  81  to the surface. The separated oil is delivered via oil supply line  82  back into the bore  15 , above the upper production barrier valve  25 , for delivery to the surface.  
         [0035]     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.  
         [0036]     In a preferred example a booster line  83  on the intervention  16  is used to provide drive fluid to power the pumps, with exhaust drive fluid returning up the riser line  84 , although the pumps could, alternatively, be powered electrically.  
         [0037]      FIG. 3  shows a configuration that can be deployed by a drilling vessel using a heavy low pressure drilling riser  89  that does not require a dedicated intervention riser  16 .  
         [0038]     The riser which is attached to the emergency disconnection package  17  is a low pressure drilling riser  89  and, 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 line  9 , as well as the separated oil, passing through a tubular pipe  88  within the riser.  
         [0039]     The tubular pipe  88  can 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 riser  89 . The drilling vessel can then run and lock the tubular pipe into the body of the emergency disconnect package connector  87  to achieve full well access.  
         [0040]     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.  
         [0041]     The riser lines  80 ,  81 ,  83  and  84  are shown as part of the riser but could equally be flexible lines hung from the surface vessel and connected to the emergency disconnect package  17 .  
         [0042]     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 in  FIGS. 2 and 3  or alternatively and as shown in  FIGS. 4 and 5  in 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.  
         [0043]      FIGS. 4 and 5  show side-by-side configurations, with the separator package  10 , emergency disconnect  17  and riser  16  mounted on a firm base, such as a pile  100 , within the sea bed and connected to a spool tree, in this case, a conventional spool tree  18  or any type of subsea production tree via a bridging line  101 , 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 bundles  110  which connect into the main field, via a manifold (not shown). Such an arrangement is shown in  FIG. 5 . This configuration allows direct vertical well intervention to the spool tree  18  or other type of subsea production tree independent of the well processing operation.  
         [0044]     The separator package  10  in  FIG. 5  could also be used in the  FIG. 1  configuration directly connected to the spool tree  18 . This allows the system to flow to a subsea field system or using a flexible bundle instead of a rigid bundle  110  to 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.  
         [0045]     Two examples of spool trees which can be utilised in the arrangement in  FIGS. 1, 2  or  3  are shown in  FIGS. 6A and 6B .  FIG. 6A  represents an external cap flow test spool tree and  FIG. 6B  shows an internal cap flow test spool tree.  
         [0046]     To prevent the requirements to remotely connect flow lines from the spool tree  18  to the separator  10 , 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.  
         [0047]     A spool tree  18  is connected and sealed to a well head  20  comprising of a connector  121  and a spool body  122 . A orientated tubing hanger  123  is supported at a precise elevation in the spool body  122 . A lateral production port  124  provides a path for the well fluid to flow to a production master valve  125 , then through a production isolation valve  126 , and into a pipeline (not shown).  
         [0048]     In the main vertical bore of the tubing hanger  123 , above the lateral port  124 , are two independent closure members  130 ,  131 . The tubing hanger is provided with its own mechanical locking system to the spool body  132  and above is a second mechanical lock system  133  providing a dual independent lockdown system.  
         [0049]     Below the tubing hanger  123  from the annulus, between the tubing  19  and the spool body  122 , a lateral port  140  connects to an annulus master valve  141 , an annulus isolation valve  142  and to an annulus pipeline (not shown). A crossover line with a crossover valve  144  provides a fluid path between the annulus and production pipework. An annulus workover path with an annulus workover valve  145  communicates with the spool body bore  150  below the top of the spool body  122 . A production port  151  communicates with the spool body bore  150  between the workover port  146  and the top of the tubing hanger  123 .  
         [0050]      FIG. 6   a  shows a external tree cap  160  with a external connector  161  connecting and sealing to the hub profile of the spool body  122 . Monitoring and venting ports are provided to access the workover port  146  and the production port  151 . The tree cap  160  provides a total seal to the spool body bore  150  and a internal cap seal  164  prevents fluid communication between workover port  146  and production port  151 .  
         [0051]     In  FIG. 1 , the separator  10  has a connector with a internal arrangement similar to the tree cap  160  that allows vertical independent production and annulus communication between the spool tree  18  and the separator  10 .  
         [0052]      FIG. 6   b  shows the use of a internal tree cap  170  that locks and seals to the internal bore of the spool body  122 . The internal tree cap  170  has a production/annulus isolation seal between the production port  151  and the annulus port  146 .  
         [0053]     In this arrangement, the spool tree will provide double mechanical pressure isolation of the well bore with or without the tree caps  160 ,  170  in place and when the separator  10  is connected.  
         [0054]     When direct well access is required, the closure members  130 ,  131  have to be opened or removed and the valve and ram barriers in the separator  10  will become the prime isolation barriers.