Abstract:
An apparatus enables modifying a riser&#39;s operating parameters for transporting production fluids from a subsea well to an offshore production facility after an initial period of production to address changes over time in the conditions of the reservoir and/or the riser without removing the original riser. An insert riser having a smaller diameter is inserted into the riser after the initial period. The original riser has a recessed seal face for receiving seal element(s) and a recessed lock groove for receiving a locking ring. An intervention coiled tubing having a sleeve removal tool is inserted into the riser to engage a protective sleeve covering the recessed seal face. The tubing is pulled to the floating structure thereby removing the protective sleeve and the temporary retaining ring from the production riser, exposing the recessed seal face. The insert riser can then be inserted into the riser and locked into place.

Description:
FIELD 
     The disclosure relates generally to methods and systems for operating a production riser in an offshore hydrocarbon production facility. More particularly, the disclosure relates to methods and systems for enabling modifications to the riser after an initial period of production. 
     BACKGROUND 
     Production risers, also known as marine risers and subsea risers, are used in offshore hydrocarbon production facilities to convey produced fluids including hydrocarbons from a subsea well to a topsides production platform or vessel. Production risers are designed and sized to meet specific mechanical requirements, e.g., fatigue life, taking into account anticipated field conditions including flow regime, fluid velocity, pressure, temperature and fluid chemistry. Excessive riser fatigue can lead to reduction in the life-span of the riser and riser replacement. 
     Design requirements for production risers change over the life of an oil and gas field, as produced fluid composition and flow regimes change. For one thing, over the life of the field, fluid velocities in a production riser decrease as flow of production fluids from a well diminishes over time. Pressure and temperature profiles of the produced fluids can change over time. Additionally, the need for corrosion resistance of the production riser may increase as a reservoir sours over time. The brownfield tie-in of other reservoirs having increased level of sour gas, i.e. carbon dioxide and hydrogen sulfide, can also increase the corrosivity of the production fluids seen by the production riser. As a result of corrosive or erosive fluids flowing through a riser, the riser may experience a reduction in wall thickness to the point that its mechanical properties are affected and it must be replaced. The need for gas lift in the production riser may increase. In certain instances, the optimum riser design parameters, e.g., internal diameter and selected material to meet the requirements for late life operations can be significantly different from the parameters required for early life operations. In such instances, a production riser may be required to be replaced during the life of the field. 
     The most common solution is to replace the production riser with a riser having a different diameter and/or different metallurgy. Such riser replacement programs require offshore installation or pipelay vessels, resulting in high capital and/or operating expense. The riser design, procurement and installation process is generally time-consuming, taking up to 24 months, depending on factors such as the degree of remoteness of the production facility, water depth, pressure, fluid composition and flowrate. Some facilities include additional riser slots to allow for the installation of a different riser once the initial production riser becomes unsuitable for use, resulting in additional capital expense. 
     It would be desirable to avoid having to replace a production riser during the life of a field. 
     SUMMARY 
     In one aspect, an apparatus is provided for facilitating a change in diameter of a riser for transporting production fluids from a subsea well to a production facility on a floating structure after an initial period of production. The apparatus includes a production riser having a topsides end for attaching to a riser hanger assembly on the floating structure, a subsea end for supporting on a pipeline end termination structure located on a seabed and attaching to a subsea pipeline, an outer production riser surface and an inner production riser surface. The inner production riser surface has a polished recessed seal face proximate the subsea end for receiving one or more seal elements and a recessed lock groove proximate the polished recessed seal face for receiving a locking ring. A protective sleeve proximate the subsea end covers the polished recessed seal face. The protective sleeve has an outer sleeve surface for partially engaging the inner production riser surface and an inner sleeve surface comprising a groove therein for receiving a sleeve removal tool. A temporary retaining ring is provided in the recessed lock groove in the inner production riser surface for holding the protective sleeve in place during the initial period of production. 
     In another aspect, a production riser system is provided for facilitating change in diameter of a riser for transporting production fluids from a subsea well to a production facility on a floating structure after an initial period of production. The production riser system includes a pipeline end termination (PLET) structure located on a seabed a distance along the seabed from the floating structure. The system includes the apparatus described above wherein the subsea end of the production riser is mounted on the pipeline end termination structure and the topsides end of the production riser is attached to the riser hanger assembly on the floating structure. 
     In another aspect, a method is provided for changing diameter of a riser for transporting production fluids from a subsea well to a production facility on a floating structure after an initial period of production. At a desired time after the initial period of production, intervention coiled tubing is inserted into the production riser of the above-described apparatus from the floating structure. The intervention coiled tubing has a sleeve removal tool at a distal end thereof. The groove of the inner sleeve surface of the protective sleeve is engaged with the sleeve removal tool. The intervention coiled tubing is pulled to the floating structure thereby removing the protective sleeve and the temporary retaining ring from the production riser and exposing the polished recessed seal face. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other objects, features and advantages of the present invention will become better understood with reference to the following description, appended claims and accompanying drawings. The drawings are not considered limiting of the scope of the appended claims. The elements shown in the drawings are not necessarily to scale. Reference numerals designate like or corresponding, but not necessarily identical, elements. 
         FIG. 1  is a simplified view of a riser apparatus according to one embodiment. 
         FIG. 2  is a simplified view of a subsea end of a riser with a protective sleeve according to one embodiment. 
         FIG. 3  is a simplified view of a riser apparatus with an insert riser inserted according to one embodiment. 
         FIG. 4  is a simplified view of a subsea end of a riser with an insert riser inserted according to one embodiment. 
         FIG. 5  is a simplified view of a riser supported by a hang off assembly on a floating structure according to one embodiment. 
         FIGS. 6A-6F  are simplified views illustrating a method for changing diameter of a riser according to one embodiment. 
     
    
    
     DETAILED DESCRIPTION 
     An apparatus is provided for facilitating a change in diameter of a riser for transporting production fluids from a subsea well to a production facility on a floating structure after an initial period of production will now be described. As shown in  FIG. 1 , in one embodiment, the apparatus  10  includes a production riser  2 , also referred to herein as a riser  2 , having a topsides end  2 A. The riser  2  can be attached at the topsides end  2 A to a riser hanger assembly  4 , also referred to herein as a riser hang off assembly  4 , located on the deck  13  of the floating structure  5 , through which the riser  2  passes. The riser hang off assembly  4  is a toroidal object having a load shoulder providing a point for the riser  2  to hang from. The top of the riser  2 A has a shoulder which rests on the hang off assembly  4 . Above the riser hanger assembly  4 , a closing spool (not shown), also referred to as a connection spool, makes the final (or closing) connection between the topsides end  2 A of the riser  2  and the permanent pipework (not show) of the topside production facilities on the floating structure  5 . 
     In one embodiment, the production riser  2  of the apparatus  10  includes has a subsea end and a section proximate the subsea end also referred to as the end section or the riser base  2 B. The riser base  2 B can be supported on a pipeline end termination (PLET) structure  8  on a seabed  1 . At the PLET  8 , the subsea end  2 B of the riser  2  can be attached to a subsea flowline  12  for transporting produced reservoir fluids including oil, gas and/or water. The riser  2  can be installed by any suitable installation means, e.g. using an offshore construction pipelay vessel (not shown). In one embodiment, the riser base  2 B supported on the PLET  8  has a thicker wall than the riser  2 . Whereas the thickness of the riser  2  can be typically 1-2 inches, the thickness of the end section  28  can be typically 2-4 inches. The length of the end section  28  can be from about 2 feet to about 6 feet. 
       FIG. 2  shows the subsea end  2 B in more detail. As shown in  FIG. 2 , in one embodiment, the riser  2  has an outer production riser surface  2 C and an inner production riser surface  2 D. In one embodiment, the inner production riser surface  2 D includes a recessed seal face  14  in the end section near or proximate the subsea end  2 B. The seal face  14 , also referred to as the seal receptacle  14 , receives temporary seal elements  16  also referred to as seal elements or seal assemblies. The seal elements  16  can be gaskets, O-rings or the like. The seal face  14  can be incorporated during the manufacture of the riser  2 . The seal face  14  is recessed so that it may receive one or more seal elements  16 . The seal face  14  is polished so that it will provide a reliable seal when the insert riser  30  (to be described hereinafter) is installed, thus sealing off the annular space, also referred to herein as the annulus, created between the production riser  2  and the insert riser  30 . A recessed lock groove  18  is located near or proximate the recessed seal face  14 . 
     In one embodiment, the riser base  2 B, i.e., the end section of the production riser  2  proximate the subsea end of the production riser  2 , is equipped with a protective sleeve  20 . The protective sleeve  20  covers the seal elements  16  to prevent erosion damage during early reservoir life production when the production riser  2  is used to transport produced fluids. The protective sleeve  20  can be retrieved via a wireline, also referred to as intervention coiled tubing or coiled tubing, from the floating production facility on the floating structure  5 , e.g. from the riser porch. 
     A protective sleeve  20  is located near or proximate the subsea end  2 B for covering the recessed seal face  14 . The protective sleeve  20  can be installed during the manufacture of the production riser  2 . The main function of the protective sleeve  20  is to protect the seal face  14 . The protective sleeve  20  has an outer sleeve surface  20 A for partially engaging the inner production riser surface  2 D and an inner sleeve surface  20 B. The inner sleeve surface  20 B has a groove  22  therein. The groove  22  can receive a sleeve removal tool (described hereinafter). The protective sleeve  20  may have a tapered shape to facilitate pigging operations. 
     A temporary retaining ring  26 , also referred to as a snap ring, which can be integral with the protective sleeve  20  locks into place in the recessed lock groove  18  to hold the protective sleeve  20  in place for a desired period of time. Alternatively, a shear pin mechanism (not shown) can be used to hold the protective sleeve  20  in place. In one embodiment, the protective sleeve  20  is held in place during the initial period of production. 
     In one embodiment, the protective sleeve  20  has a recessed shoulder profile, i.e., the groove  22 , on the inside bore to facilitate retrieving the protective sleeve  20  from the riser  2 . A mechanical running and retrieval tool (described hereinafter) can be deployed on coiled tubing to engage the recessed shoulder profile to retrieve the protective sleeve  20  from the riser  2 . 
     In one embodiment, an insert riser  30  is inserted into the production riser  2  such that the apparatus  10  further includes the insert riser  30 . The insert riser  30  can be a length of coiled tubing, steel pipe, or downline pipe made of any suitable material such as steel pipe, composite pipe and the like.  FIG. 3  shows the system as illustrated in  FIG. 1  in which the apparatus  10  further includes the insert riser  30 . 
     In one embodiment, when the insert riser  30  is inserted into the production riser  2 , an annulus  38  is formed between the outer surface  30 A of the insert riser  30  and the inner surface  28  of the production riser  2 .  FIG. 4  shows the subsea end  2 B with the insert riser  30  inserted in more detail. One or more seal elements  32  are provided around the outer surface  30 A of the insert riser  30 . The seal elements  32  are capable of engaging the recessed seal face  14  of the production riser  2 . In one embodiment, a locking ring  34  is provided around the outer surface  30 A of the insert riser  30 . The locking ring  34  is capable of fitting into the recessed lock groove  18  of the production riser  2 . 
     Referring to  FIG. 3 , in one embodiment, the insert riser  30  includes a plurality of centralizers  36  along the length of the insert riser  30  for centering the insert riser  30  within the production riser  2 . 
     Referring to  FIG. 5 , riser  2  is supported above the deck  13  of the floating structure  5  by a hang off clamp  11  attached to a hang off assembly  4  on the deck  13 . In one embodiment, the top end of the apparatus  10  includes a spool connection  43 , also referred to herein as an insert riser hang off spool  43 , located between the closing spool  15  and the riser  2 , above the deck  13 . The top end of the riser  2 A attaches to the lower end of the spool connection  43 . In one embodiment, the spool connection  43  has at least one inlet  46  therein for introducing gases into the annulus  38 . The inlet  46  can have an injection check valve  42  in the inlet  46  for providing fluid flow between an external source (not shown) of gases on the floating structure and the annulus  38 . The inlet  46  provides an access point at the riser hang off for controlling fluid types, levels and pressures within the annulus  38 . In one embodiment, the spool connection  43  further seals off production from the annulus  38 . Through the inlet  46 , gas lift can be provided to the annulus  38  to assist with production in the insert riser  30  by way of an optional side pocket mandrel  44 . In such case, a side pocket mandrel  44  can be located within the insert riser  30  at any desired location along the length thereof. The side pocket mandrel  44  can be a screwed pipe connection located at a predetermined point in the insert riser  30  with a check valve (not shown) installed in the mandrel pocket that allows gas to flow from the annulus  38  into the production bore within the insert riser  30  to lighten the column of fluid and increase flow of hydrocarbons. 
     In one embodiment, the apparatus  10  includes seal assemblies  40 , also referred to as gaskets  40 , to seal the annulus  38 . Gaskets  40  can be located between the topsides end  2 A of the production riser  2  and the insert riser hang off spool  43 , between the insert riser  30  and the hang off spool  43 , and between the insert riser hang off spool  43  and the closing spool  15 . 
     In one embodiment, referring to  FIG. 3 , a production riser system is provided that includes the apparatus  10  as described above. The production riser  2  transports production fluids from a subsea well (not shown) to the production facility on the floating structure  5 . The PLET structure  8  is located on the seabed  1  a distance along the seabed from the floating structure  5 . The subsea end  2 B of the production riser  2  is mounted on the PUT structure  8 . The topsides end  2 A of the production riser  2  is attached to the riser hanger assembly  4  on the floating structure  5 . 
     In one embodiment, illustrated in  FIGS. 6A-6F , a method is provided for changing a diameter of a riser for transporting production fluids from a subsea well to a production facility on a floating structure after an initial period of production. As shown in  FIG. 6A , at a desired time after the initial period of production, tubing  7 , e.g., intervention coiled tubing, is inserted into the production riser  2  of the apparatus  10  from the floating structure  5 . The intervention coiled tubing  7  has a sleeve removal tool  9  at a distal end  7 D thereof. 
     As shown in  FIG. 6B , the groove  22  of the inner sleeve surface  20 B of the protective sleeve  20  is engaged with the sleeve removal tool  9 . As shown in  FIG. 6C , the intervention coiled tubing  7  is pulled to the floating structure  5 , thereby removing the protective sleeve  20  and the temporary retaining ring  26  from the production riser  2  and exposing the polished recessed seal face  14  as shown in  FIG. 6D . 
     Once the protective sleeve  20  and temporary retaining ring  26  have been removed and the seal face  14  has been exposed, the insert riser  30  is inserted into the production riser  2  from the floating structure  5 , as shown in  FIG. 6E . The insert riser  30  can either be installed using coiled tubing for smaller diameter lines, or by joining together 30 foot sections of tubing on the main deck  13  of the floating structure  5  using a workover mast (not shown). The one or more seal elements  32  around the outer surface of the insert riser  30  engage the recessed seal face  14 . The locking ring  34  around the outer surface of the insert riser  30  fits into the recessed lock groove  18 , as shown in  FIG. 6F . 
     In one embodiment, the top of the production riser  2  can be hung off the floating structure  5  in a riser hang off above a flex joint that includes a seal assembly to isolate the annulus  38  that is created by installing the insert riser  30 . 
     The production riser  2  remains present around the insert riser  30 , thus it acts as a carrier pipe that protects the insert riser  30 . The insert riser  30  therefore need not be designed to the same design requirements as the production riser  2  because the insert riser  30  will not see the same dynamic forces as the production riser  2 . The insert riser  30  can rely on the production riser  2  to provide structural protection against environmental loading and the marine environment, while the insert riser  30  will contain and seal the fluid path. 
     The desired time after the initial period of production can be selected for any of a number of reasons. For instance, in one embodiment, the desired time can be when there is evidence of significant reservoir souring having occurred in the field. The desired time can be at a time when other fields are tied in to the field. The desired time can be when the production riser  2  has shown signs of wall thinning or similar damage. The desired time can be when flow rate of production fluids from the reservoir has decreased substantially, thus requiring either smaller diameter, or artificial lift, such as gas lift or insertion of an electric submersible pump (ESP). Any event that would trigger replacing the production riser  2  can mark the desired time. 
     Once the insert riser  30  is installed, the seal at the PLET  8  and/or the insert riser  30  can be pressure tested to ensure no leaks are present in the production riser system. 
     In certain embodiments, the annulus  38  between the insert riser  30  and the production riser  2  can advantageously be used for a variety of beneficial purposes in addition to changing the riser diameter. For instance, in one embodiment, the annulus  38  can be used to provide gas lift to enhance the flow of production fluids as previously described. 
     In one embodiment, the annulus  38  can be used to provide a pathway for chemicals to be injected at predetermined points or liquid penetrators  48 . Chemicals can be injected for a variety of purposes, including but not limited to hydrate prevention, wax prevention and corrosion inhibition. When larger volumes of chemicals are required, e.g. when continuously injecting methanol or monoethylene glycol (MEG), the chemicals can be introduced into the annulus  38  and the annulus  38  can be flooded with the chemicals. The chemicals can be introduced by tubing  50 . The tubing  50  can extend from a source of the chemicals, through a liquid penetrator  48  and into the annulus  38 . The tubing  50  can have an open subsea end for delivering the chemicals into the annulus  38  at a subsea e.g., at the PLET  8 . 
     In one embodiment, the annulus  38  itself provides thermal insulation around the insert riser  30 . 
     In one embodiment, the riser base has the capability to establish communication between the production flow path within the insert riser  30  and the annulus  38 . In such case, the insert riser  30  is only partially inserted into the production riser  2  so that the seal elements  32  of the insert riser  30  do not actually engage the recessed seal face  14  of the production riser  2 . A flow path is thereby provided from the inner surface of the insert riser  30  into the production riser  2  around the distal end of the insert riser  30 . A fluid can thus be injected into the insert riser  30  from the floating structure  5 . The fluid can be allowed to flow along the flow path to flush the annulus  38  between the insert riser  30  and the production riser  2 . In one embodiment, this method can be used to force a desired the fluid in the annulus  38  and another fluid in the insert riser  30  bore. For instance, one of the chemicals described above can be in the annulus  38  and diesel or gas in the bore of the insert riser  30 . In one embodiment, this method can be used to change column fluid densities to aid in startup of the well. 
     In one embodiment, the annulus  38  can be used as part of an active heating system. In one embodiment, the annulus  38  may be used to pump hot water in a total loss system, where the water being pumped through the annulus  38  is used to heat the production fluids within the insert riser  30 . The hot water may then be vacated to the sea. In one embodiment, electric heat tracing (not shown) may be attached to the insert riser  30  to heat the production fluids within the insert riser  30 , thereby facilitating fluid flow and preventing the formation of hydrates. 
     In one embodiment, the annulus  38  can be used in a multifunctional pipeline system as disclosed in U.S. Pat. No. 8,950,499, the contents of which are incorporated herein by reference. In embodiments in which during initial engineering it is identified that the internal diameter of the insert riser  30  is too small to allow pigging, the PLET can leverage embodiments disclosed in U.S. Pat. No. 8,950,498, the contents of which are incorporated herein by reference. 
     Use of the apparatus, systems and methods of the present disclosure can result in significant cost savings. In one nonlimiting, illustrative example, a 20 in diameter subsea catenary riser is installed in 1000-meter-deep water in a “Lazy-S” configuration at vessel and labor cost (mobilization and demobilization) plus material cost per riser length. By using the system of the disclosure, operating expense and capital expense reductions can be realized. 
     It should be noted that only the components relevant to the disclosure are shown in the figures, and that many other components normally part of a production riser system are not shown for simplicity. 
     For the purposes of this specification and appended claims, unless otherwise indicated, all numbers expressing quantities, percentages or proportions, and other numerical values used in the specification and claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that can vary depending upon the desired properties sought to be obtained by the present invention. It is noted that, as used in this specification and the appended claims, the singular forms “a,” “an,” and “the,” include plural references unless expressly and unequivocally limited to one referent. 
     Unless otherwise specified, the recitation of a genus of elements, materials or other components, from which an individual component or mixture of components can be selected, is intended to include all possible sub-generic combinations of the listed components and mixtures thereof. Also, “comprise,” “include” and its variants, are intended to be non-limiting, such that recitation of items in a list is not to the exclusion of other like items that may also be useful in the materials, compositions, methods and systems of this invention. 
     This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. The patentable scope is defined by the claims, and can include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. All citations referred herein are expressly incorporated herein by reference. 
     From the above description, those skilled in the art will perceive improvements, changes and modifications, which are intended to be covered by the appended claims.