Patent Publication Number: US-7213657-B2

Title: Apparatus and methods for installing instrumentation line in a wellbore

Description:
BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The invention generally relates to methods and apparatus for connecting instrumentation lines in a wellbore. More particularly, the invention provides methods and apparatus for delivering a fiber optic cable to a selected depth within a hydrocarbon wellbore. 
   2. Description of the Related Art 
   In a typical oil or gas well, a borehole drilled into the surface of the earth extends downward into a formation to provide a wellbore. The wellbore may include any number of tubular strings such as a string of surface casing cemented into place and a liner string hung off of the casing that extends into a producing zone, or pay zone, where the liner is perforated to permit inflow of hydrocarbons into the bore of the liner. Alternatively, the wellbore may be completed as an open hole which may include a sand screen positioned at the end of the casing to support the formation and filter hydrocarbons that pass therethrough. During the life of the well, it is sometimes desirable to monitor conditions in situ. Recently, technology has enabled well operators to monitor conditions within a wellbore by installing permanent monitoring systems downhole. The monitoring systems permit the operator to monitor such parameters as multiphase fluid flow, as well as pressure and temperature. Downhole measurements of pressure, temperature and fluid flow play an important role in managing oil and gas or other sub-surface reservoirs. 
   Historically, permanent monitoring systems have used electronic components to provide pressure, temperature, flow rate and water fraction data on a real-time basis. These monitoring systems employ temperature gauges, pressure gauges, acoustic sensors, and other instruments, or “sondes,” disposed within the wellbore. Such electrical instruments are either battery operated, or are powered by electrical cables deployed from the surface. Typically, conductive electrical cables transmit the electrical signals from the electronic sensors back to the surface. 
   Recently, optical sensors have been developed which communicate readings from the wellbore to optical signal processing equipment located at the surface. The optical sensors may be variably located within the wellbore and do not require an electrical line from the surface. For example, optical sensors may be positioned in fluid communication with the housing of a submersible electrical pump. Such an arrangement is taught in U.S. Pat. No. 5,892,860, issued to Maron, et al., in 1999. The &#39;860 patent is incorporated herein in its entirety, by reference. Optical sensors may also be disposed along the tubing within a wellbore to sense the desired parameters. As another example of an optical sensor, a distributed temperature sensor system is a known measurement technique that provides a continuous temperature profile along the entire length of an optical fiber. Distributed temperature sensor systems operate on the principle of backscattering, the known velocity of light and the thermal energy in the optical fiber. Regardless of the type of optical sensor, an optical waveguide or fiber optic cable runs from the surface to the optical sensor downhole. Surface equipment transmits optical signals to the downhole optical sensors via the fiber optic cables which transmit return optical signals to an optical signal processor at the surface. 
   Therefore, both optical and electronic sensors often require an instrumentation line such as a fiber optic cable, a wire or a conductive electric cable that runs down the wellbore to the sensor. The instrumentation line may run down the outer surface of one of the tubular strings in the wellbore such as production tubing and clamp thereto at intervals as is known in the art. When the instrumentation line is on the outside of a liner or sand screen, the instrumentation line may be subjected to trauma or damage as the liner or sand screen runs into the wellbore. Trauma further increases where the instrumentation line is disposed along the outer surface of an expanded liner or sand screen since the instrumentation line compresses between the outer surface of the liner or sand screen and the surrounding formation. 
   Further, the instrumentation line may be exposed to the harsh effects of chemicals used in well completion or remediation operations. For example, it is oftentimes desirable to wash the tubing in order to remove grease and contaminants during a last stage in well completion. This is accomplished by circulating acid through the tubing. In addition, an acid wash or other stimulant may clean the sand screen and tubing of paraffins, hydrates and scale that accumulate along the sand screen and tubing during the life of a producing well. The application of such chemicals may be detrimental to the integrity of the instrumentation line. This is particularly true where the instrumentation line is a fiber optic cable of a distributed temperature sensor system. A packer may isolate an upper section of the instrumentation line from the chemicals used in the well completion or remediation operations such that only a lower section of the instrumentation line is subject to the harsh chemicals. 
   The expandable sand screen may include protective features that help protect the instrumentation line disposed along the outside of the sand screen as the sand screen is run and expanded. For example, the instrumentation line may pass along a recess in the outer diameter of the sand screen. Arrangements for the recess are described more fully in the application entitled “Profiled Recess for Instrumented Expandable Components,” having Ser. No. 09/964,034, now U.S. Pat. No. 6,877,553 issued Apr. 12. 2005. which is incorporated herein in its entirety, by reference. Alternatively, a specially profiled encapsulation around the sand screen which contains arcuate walls may house the instrumentation line. Arrangements for the encapsulation are described more fully in the application entitled “Profiled Encapsulation for Use with Expandable Sand Screen,” having Ser. No. 09/964,160, now U.S. Pat. No. 6,932,161 issued Aug. 23, 2005, which is also incorporated herein in its entirety, by reference. However, these protective features fail to protect the instrumentation line from the chemicals used during well completion and remediation operations. With the instrumentation line clamped to a liner or sand screen and/or disposed in a protective feature of a sand screen, it is not possible to pull the instrumentation line during an acid wash or other remedial operation, at least not without pulling the tubular and/or sand screen. 
   Therefore, there exists a need for a method of installing an instrumentation line into a wellbore after expansion of a sand screen or other liner, after setting of a packer, and/or after conducting an acid wash. Further, a need exists for a coupling apparatus that permits a lower instrumentation line to connect downhole with an upper instrumentation line after the upper instrumentation line is placed in the wellbore. There exists a further need for a coupling apparatus that allows the lower instrumentation line to be detached and removed from the wellbore without removing the upper instrumentation line. 
   SUMMARY OF THE INVENTION 
   The invention provides a coupler and a method for installing an instrumentation line, such as fiber optic cable, into a wellbore. The coupler places upper and lower instrumentation lines in communication with one another downhole to form a single line. The apparatus comprises a landing tool and a stinger that lands on the landing tool, thereby placing the upper and the lower instrumentation lines in communication. The landing tool is run into the wellbore at the lower end of a tubular, such as production tubing. The upper instrumentation line affixes to the tubing and landing tool and extends to the surface. The lower instrumentation line affixes along the stinger. In this manner, the lower instrumentation line may be installed after expansion of a well screen or liner and may be later removed from the wellbore prior to well workover procedures without pulling the production string. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
       FIG. 1  is a partial sectional view of a wellbore having a coupler that includes a landing tool at the end of a tubular string and a stinger landed in the landing tool. 
       FIG. 2  is a partial sectional view of the landing tool in a run-in position. 
       FIG. 2A  is an enlarged partial sectional view of a portion of the landing tool of  FIG. 2 . 
       FIG. 3  is a perspective view in partial section of a connector guide of the landing tool that houses a connector for an upper instrumentation line. 
       FIG. 4  is a perspective view of an upper portion of an orienting sleeve of the landing tool. 
       FIG. 5  is a partial sectional view of the stinger. 
       FIG. 5A  is an enlarged sectional view of a portion of the stinger shown in  FIG. 5 . 
       FIG. 6  is a partial sectional view of the coupler in an intermediate position with the stinger partially within the landing tool. 
       FIGS. 6A and 6B  are enlarged partial sectional views of the coupler shown in  FIG. 6  in the intermediate position. 
       FIG. 7  is a cross section view of the coupler across line  7 — 7  in  FIG. 6A . 
       FIG. 8  is a partial sectional view of the coupler in a connected position with the stinger landed within the landing tool. 
       FIG. 9  is a cross section view of the coupler across line  9 — 9  in  FIG. 8 . 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1  illustrates a partial sectional view of an exemplary wellbore  50  that may receive a coupler  100  of the invention. While the coupler  100  is shown generally in  FIG. 1 , the detail of the coupler  100  will be described in detail with reference to the various figures hereinafter. The wellbore  50  includes a string of casing  20  secured within a surrounding earth formation  25  by cement  30 , a tubular string such as production tubing  35  run into the casing  20 , an instrumentation line  12  and a packer  40  that seals the annular region  45  between the tubing  35  and the surrounding casing  20 . The wellbore  50  is completed with a screen hanger  60  that supports a sand screen  65  adjacent a desired pay zone  55 . As shown, the coupler  100  connects to the tubing  35  by a flow sub  70 . The flow sub  70  includes perforations  75  that permit the inflow of hydrocarbons for production and the circulation of chemicals around the coupler  100  during later well completion or remediation operations. 
   The instrumentation line  12  includes an upper instrumentation line  12 U and a lower instrumentation line  12 L. The instrumentation lines  12 U,  12 L may be an electrical line, an optical waveguide or a cable comprised of both optical fibers and electrical wires. Where the instrumentation lines  12 U,  12 L are fiber optic lines, the lines  12 U,  12 L may be part of a distributed temperature sensor system, a pressure and temperature sensor system, a flow meter, an acoustic sensor system, a chemical sensor, a seismic sensor or any other type of sensor or system including combinations thereof. In any case, the lower instrumentation line  12 L is recoverably delivered to the depth of the pay zone  55  such that the line  12 L extends to a level within the wellbore  50  below the packer  40  and adjacent the sand screen  65 . The upper instrumentation line  12 U runs along the tubing  35  to the surface and is connected to surface instrumentation  132 . 
   The invention is directed to the coupler  100  and a method for using the coupler  100 . The coupler  100  places the upper  12 U and lower  12 L instrumentation lines in communication with one another, thereby forming the single instrumentation line  12 . However, the operator may remove the lower instrumentation line  12 L from the wellbore  50  at any time after the coupler  100  has placed the upper and lower instrumentation lines  12 U,  12 L in communication. In this manner, the lower portion  12 L of the instrumentation line  12  is spared trauma from later remediation or well workover procedures. Therefore, the wellbore completion arrangement shown in  FIG. 1  is for exemplary purposes only. The invention is not limited as to the manner of completing the well, and the coupler  100  may be employed in any open hole completion, cased hole completion, injection well, lateral well, horizontal well or other known or contemplated wells as can be appreciated by one skilled in the art. 
   The coupler  100  comprises a landing tool  200  and a stinger  300  that are connected to one another downhole. In operation, the landing tool  200  is disposed at the lower end of the tubing  35 , and the upper instrumentation line  12 U connects to the landing tool  200  and runs into the wellbore  50  with the tubing  35  and landing tool  200 . The lower instrumentation line  12 L connects to the stinger  300 . The stinger  300  releasably couples to a working string such as coiled tubing string (not shown) and runs into the wellbore  50  on the working string after the tubing  35  and landing tool  200  are in place. In this manner, the stinger  300  lands on the landing tool  200  as shown in  FIG. 1  to bring the upper and lower instrumentation lines  12 U,  12 L together and provide the instrumentation line  12  as will be explained more fully hereinafter. Thereafter, the working string releases from the stinger  300  and the working string is removed from the wellbore  50 . As shown, the length of the stinger  300  that extends from the landing tool  200  may be selected such that lower instrumentation line  12 L that is attached to the stinger  300  is positioned at the desired depth within the wellbore  50 . 
     FIG. 2  shows a partial section view of a portion of the landing tool  200  of the coupler  100  in a run-in position. The landing tool  200  includes a series of tubular subs connected by threads or otherwise in order to form an elongated tubular body. As shown in  FIG. 8  with the landing tool  200  and stinger  300  of the coupler  100  in the connected position, the landing tool  200  receives a portion of the stinger  300  within the bore of the elongated tubular body. A landing profile  236  located on the inner diameter of the landing tool  200  mates with a corresponding landing shoulder  366  of the stinger  300  to limit movement of the stinger  300  through the landing tool  200 . One of the tubular subs of the landing tool  200  is an offset mandrel  210  having an enlarged outer diameter portion  216 . The landing tool  200  may include additional tubular subs or a combination of one or more of the subs shown integrated into a single sub depending upon the manufacturing protocol. In the arrangement shown in  FIG. 2 , the landing tool  200  includes several subs in addition to the offset mandrel  210 . For example, the landing tool  200  may include an upper locking sub  220  having a profile  226  along its inner diameter for receiving locking dogs  426  of an optional latching mechanism  400  of the stinger  300  as shown in  FIG. 8 . 
   An orienting sleeve  280  shown disposed within the offset mandrel  210  of the landing tool  200  is rotationally fixed within the offset mandrel  210 . Preferably, the orienting sleeve  280  threads into the inner diameter of the offset mandrel  210 . In the arrangement shown in  FIG. 2 , the lower end of the orienting sleeve  280  threads down onto a shoulder along the inner diameter of the offset mandrel  210 . However, a weld or other connection may be provided. The orienting sleeve  280  provides proper rotational orientation for the stinger  300  as the stinger  300  lands into the landing tool  200 . To this end, the upper end of the orienting sleeve  280  includes an orienting shoulder  286  that receives a key  388  of the stinger  300  when in the connected position shown in  FIG. 8 . In one arrangement, the orienting shoulder  286  is helical.  FIG. 4  provides a prospective view of the top portion of the orienting sleeve  280  with the helical orienting shoulder  286 . The orienting shoulder  286  includes a bottom-out edge  288  into which the key  388  of the stinger  300  is guided. 
   Referring to  FIG. 2A , the enlarged outer diameter portion  216  of the offset mandrel  210  includes a debris sleeve  250  and a pocket  218  that houses a bow spring  290 . The pocket  218  of the landing tool  200  houses an upper connector  270  within a connector guide  278  in the run-in position. The upper connector  270  connects to the lower end of the upper instrumentation line  12 U. While only the lowest portion of the upper instrumentation line  12 U is shown, it is understood that the line  12 U runs to the surface. In the run-in position for the landing tool  200 , the upper end of the debris sleeve  250  shoulders against a debris sleeve shoulder  219  along the inner diameter of the offset mandrel  210 . However, the debris sleeve  250  is slideable along the inner diameter of the offset mandrel  210 . The debris sleeve  250  includes a window  256  milled in a wall thereof. As the debris sleeve  250  is pushed downward during operation relative to the offset mandrel  210 , the window  256  in the debris sleeve  250  moves adjacent the offset mandrel pocket  218 . This serves to expose the connector  270  for the upper instrumentation line  12 U to the inner bore  205  of the offset mandrel  210 . This, in turn, allows the bow spring  290  to act against the connector guide  278  and urge the connector  270  through the window  256  of the debris sleeve  250  in order to align with the mating connector  370  of the stinger  300 . For other embodiments, hydraulic force through coiled tubing, or other type of force, may also be used to urge the connector guide  278  inwardly toward the lower connector  370  of the stinger  300 . 
     FIG. 3  shows a perspective view of the connector guide  278  apart from the offset mandrel  210 . The connector guide  278  includes an opening  275  for receiving the lower end of the upper instrumentation line  12 U (not shown) and at least a portion of the connector  270  (not shown). The connector guide  278  also includes a pair of pin grooves  273 . As will be discussed in greater detail below, the opposing pin grooves  273  receive pins  373  within the debris sleeve  250  as shown in  FIG. 9 . As the bow spring  290  urges the connector guide  278  inwardly towards the bore  205  of the offset mandrel  210 , the pins  373  mate with the pin grooves  273  to align the connector guide  278  and housed upper connector  270  with a lower connector  370  in the stinger  300 . 
   Referring back to  FIG. 2A , the debris sleeve  250  includes an upper snap ring  251 , a lower snap ring  253  and an optional pair of debris wipers  255 . In the run-in position shown in  FIG. 2A , the upper snap ring  251  resides within a snap ring profile  211  along the offset mandrel  210  and the lower snap ring  253  resides closely around the debris sleeve  250 . Both the upper and lower snap rings  251 ,  253  are biased outward. Therefore, the bias of the upper snap ring  251  maintains the upper snap ring  251  within the snap ring profile  211  until forced inwardly when sufficient force is applied against the top of the debris sleeve  250 , thereby releasing the debris sleeve  250  from its axial location within the offset mandrel  210 . This, in turn, permits the debris sleeve  250  to slide downwardly within the inner diameter of the offset mandrel  210 . Thus, once the debris sleeve slides downward, the lower snap ring  253  expands into a lower snap ring profile  213  (shown in  FIG. 2 ) along the offset mandrel  210 . The debris wipers  255  essentially define elastomeric (or other pliable material) seals disposed circumferentially around the debris sleeve  250 . The debris wipers  255  are placed at opposite ends of the window  256 , and serve to keep debris from entering the window  256  and the pocket  218  of the offset mandrel  210 . 
     FIG. 5  illustrates a partial sectional view of a portion of the stinger  300  of the coupler  100  as shown in  FIG. 1  and  FIG. 8 . As with the landing tool  200 , the stinger  300  generally defines an elongated tubular body that includes a series of subs connected end-to-end. As shown, the stinger  300  includes subs such as a connector mandrel  310 , a collet mandrel  330 , a no-go sub  360 , and at least one stinger sub  390  that connect to a lower end of one another successively by threads or otherwise. The connector mandrel  310  has an outer diameter dimensioned to be closely received within the inner diameter of both the orienting sleeve  280  and the debris sleeve  250  of the landing tool  200  as shown in  FIG. 8 . Disposed along the outer diameter of the connector mandrel  310  is the key  388 . The key  388  represents a fixed protrusion that catches the orienting shoulder  286  of the orienting sleeve  280  when the stinger  300  is lowered into the landing tool  200 . Also visible in  FIG. 5  is the landing shoulder  366  for landing in the landing profile  236  of the landing tool  200  as described above. A no-go collar attached to the upper end of the no-go sub  360  serves as the shoulder  366  for the stinger  300 . 
   The stinger subs  390  define an elongated tubular body that extends downward into the pay zone  55  of the wellbore  50  as shown in  FIG. 1  or to any other depth where the sensors are desired. The lower instrumentation line  12 L (shown in  FIG. 1 ) attaches along the length of the stinger subs  390 . The lower instrumentation line  12 L may be clamped along the outer surface of the stinger subs  390 , may dangle within a bore of the stinger  300  or dangle freely in the wellbore below the stinger subs  390 . 
   The connector mandrel  310  includes a milled pocket  356  and a channel  351  extending from the pocket  356 . The milled pocket  356  houses a lower connector  370  that is connected to the lower instrumentation line  12 L. From the connector  370 , the lower instrumentation line  12 L travels through the channel  351 . The lower instrumentation line  12 L exits the channel  351  and turns back to run downward along the stinger  300 . In one arrangement, the line  12 L runs through a bore  315  (visible in the cross section views of  FIG. 7  and  FIG. 9 ) of the stinger  300 . As illustrated in  FIG. 8 , the pocket  356  of the connector mandrel  310  also receives the connector guide  278  of the landing tool  200  when the coupler is in the connected position. The pocket  356  is deep enough to permit the upper connector  270  to completely clear the inner diameter of the offset mandrel  210 . This, in turn, allows the upper connector  270  in the landing tool  200  to properly align in a radial direction with the lower connector  370  in the stinger  300  which is already aligned rotationally by the interaction of the key  388  with the orienting sleeve  280 . 
   Referring to  FIG. 5A , a lower end of the collet mandrel  330  defines a collet stop  334 . The collet stop  334  serves as a shoulder against which a collet  340  disposed around the collet mandrel  330  may be attached. The collet  340  has a base  344  connected to the collet stop  334  of the collet mandrel  330 . In addition, the collet  340  has a plurality of outwardly biased fingers  348 . The collet fingers  348  have an outer profile  346  that mates with a collet profile  259  (shown in  FIG. 2  and  FIG. 2A ) along the inner diameter of the debris sleeve  250 . 
     FIG. 6  illustrates an intermediate position of the coupler  100  as the stinger  300  traverses into the landing tool  200 . Visible in the enlarged views of  FIG. 6A  and  FIG. 6B , the outer profile  346  along the collet fingers  348  engage the collet profile  259  along the debris sleeve  250 . Thus, axial movement of the stinger  300  transfers to the debris sleeve  250  in the landing tool  200  and shifts the debris sleeve  250  downward in order to expose the pocket  218  in the offset mandrel  210 . As shown in the intermediate position, a small portion of the debris sleeve  250  adjacent the lower end of the window  256  continues to block outward movement of the connector guide  278  and housed upper connector  270  of the landing tool  200 . Thus, the two connectors  370 ,  270  are not yet aligned since the connector guide  278  for the upper instrumentation line connector  270  has not yet moved inwardly and the key  388  has not yet seated in the bottom-out edge  288  of the orienting sleeve  280  in order to rotationally orient the lower connector of the stinger  300  when the coupler  100  is in the intermediate position as shown in  FIG. 6 . 
     FIG. 7  is a cross-sectional view of the coupler  200  taken across line  7 — 7  of  FIG. 6A . As shown, the offset mandrel  210  includes a cap  292  on one side that serves as a spring housing. The cap  292  connects to the offset mandrel  210  by one or more fasteners  294 . Also visible within the cross-sectional view of  FIG. 7  is the connector guide  278  having the opening  275  for housing the connector  270 . The pin grooves  273  are seen along the connector guide  278  for receiving the pins  373  within the debris sleeve  250 . The bow spring  290  is in a compressed state, but is biased to urge the connector guide  278  inward. However, a flat surface  250 ′ in the debris sleeve  250  butts against the connector guide  278  and prevents the connector guide  278  from moving inward towards the center of the coupler  100  since the coupler  100  is in the intermediate position. 
     FIG. 8  shows the coupler  100  in the connected position. In the connected position, the landing shoulder  366  of the stinger  300  contacts or lands on the profile  236  of the landing tool  200 . As the stinger  300  moves between the intermediate position and the connected position, the bow spring  290  acts on the connector guide  278  that is no longer restrained by the debris sleeve  250  and urges the connector guide  278  inwardly towards the connector mandrel  310  of the stinger  300  such that the upper connector  270  aligns with the lower connector  370 . Further, the key  388  of the stinger contacts the shoulder  286  and rotates the stinger  300  to position the key  388  within the bottom-out edge  288 . This rotationally aligns the connectors  270 ,  370 . As seen in the cross section view in  FIG. 9 , the pins  373  engage the grooves  273  along the connector housing  278 , further aligning the upper connector  270 . 
   Merely because the upper instrumentation line connector  270  has aligned with the lower instrumentation line connector  370  does not mean that communication has taken place as between the two connectors  270 ,  370 . For example, where the two lines  12 L,  12 U are fiber optic lines, it is possible that oil residue or debris could come between the two connectors  270 ,  370 , preventing optical communication. In this instance, it is desirable to pull the stinger  300  back up within the landing tool  200  before locking the stinger  300  in the landing tool  200  and circulate a cleaning fluid through a bore of the stinger  300 . Thereafter, a reconnection can be attempted between the connectors  270 ,  370 . 
   Once the coupler  100  is in the connected position and communication is established, the stinger  300  may be locked in the landing tool  200  with an optional latching mechanism  400  at the top of the stinger  300 . The latching mechanism allows the position of the stinger  300  to be axially locked relative to the landing tool  200  and permits release of the stinger  300  from the landing tool  200  in the event it is desired to remove the stinger  300  from the wellbore  50 . Any known releasable latching mechanism may be used between the stinger  300  and the landing tool  200  of the coupler  100 . As shown, the latching mechanism  400  includes locking dogs  426  that are selectively moved outward into the profile  226  of the landing tool  200 . 
   After the coupler  100  is in the connected position and when the stinger  300  is unlocked from the landing tool  200 , the stinger  300  may be raised back up within the landing tool  200 . In this manner, it is possible to return to the intermediate position shown in  FIG. 6  or run-in position after placing the coupler  100  in the connected position shown in  FIG. 8 . Referring to  FIG. 6 , a beveled surface  357  is provided along the pocket  356  of the connector mandrel  310 . The beveled surface  357  matches a beveled surface  276  of the connector guide  278 . Thus, as the stinger  300  axially raises relative to the landing tool  200 , the beveled surface  357  of the connector mandrel  310  engages the beveled surface  276  of the connector guide  278  and urges it back outwardly towards the pocket  218  in the offset mandrel  210 . The outward force of the connector mandrel  310  on the connector guide  278  overcomes the inward force of the bow spring  290 . In this manner, the stinger  300  can be raised for circulation of cleaning fluid when attempting to establish communication or completely removed from the wellbore during well completion and remediation procedures that may damage the lower instrumentation line  12 L. 
   While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.