BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments of the present invention generally relate to a method and apparatus for injecting material, like steam into predetermined zones surrounding a wellbore.
Description of the Related Art
The present invention relates to the selective treatment of wellbore zones, typically by the injection of steam. Traditional means of injecting steam to various locations in a wellbore means placing valves in a tubular string and then opening the valves by shifting sleeves with wireline. However, in steam injection wells there are working limits regarding bottom hole temperature and surface temperature as to when wireline can be used. High temperatures in these type wells can reduce the tensile strength of the wire and high surface pressure and temperature of steam can be very hazardous to service personnel required around the wellhead. There is a need therefore, for a new and improved way to inject steam at various predetermined locations in a wellbore.
SUMMARY OF THE INVENTION
The present invention includes methods and apparatus for selectively treating different zones in a wellbore. In one embodiment, a method is performed by running a tubular string into the wellbore, the string having at least two housings disposed therein, the housings separated along the string, each housing having a fluid path between an interior of the housing and a zone of interest and each housing having an individual profile for mating with an individual insert; running a second, smaller diameter tubular string into the wellbore, the string including an insert, the insert constructed and arranged to mate with a predetermined one of the plurality of housings and to initially seal the fluid path; mating the insert to the predetermined housing, thereby sealing the fluid path; dropping an object from the surface of the well, the object constructed and arranged to land in a ball seat formed in the insert; using fluid pressure to open the fluid path and injecting material into the zone, via the fluid path.
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 section view of a wellbore with a production string disposed therein.
FIG. 2 is a section view of the wellbore of FIG. 1 showing an upper housing in greater detail.
FIG. 3 is a partial section view of the wellbore showing the upper housing of FIG. 2 and also illustrating the insertion of a lower wellbore flow control insert.
FIG. 4 is a view, partially in sections, showing the lower housing and the lower wellbore flow control insert installed in the housing.
FIG. 5 is a section view of the wellbore showing the upper wellbore flow control insert installed in the upper housing.
FIG. 6 is a section view of the wellbore illustrating the lower wellbore flow control insert disposed in the lower housing and showing a lower ball sleeve flow control insert plug in its initial closed position where it is retained by a shear pin.
FIG. 7 is a section view of the components of FIG. 6 and illustrates the lower ball seat as it moves between its initial closed position to an open position.
FIG. 8 is a section view of the wellbore showing the lower wellbore flow control insert and housing with the lower ball sleeve flow control insert plug in the open position and a “treatment” of the lower zone in progress.
FIG. 9 is a section view of the wellbore showing the production of hydrocarbons in the upper housing and wellbore flow control insert from an upper zone as well as from zones below the upper housing.
DETAILED DESCRIPTION
FIG. 1 is a section view of a wellbore 100 with a production string 110 disposed therein. As illustrated, the production string includes an upper 200 and lower 300 housing installed at predetermined locations where they will each be adjacent an area of interest or zone (e.g., 202, 302). Packers 205, 210, 305, 310 are used to isolate annular areas (e.g., 212, 312) between the housings and the zones. As will be explained in more detail, each housing (e.g., 200, 300) includes an internal profile (e.g., 215, 315) designed to interact and mate with corresponding outer profiles of a particular wellbore flow control insert (not shown) and permit other wellbore flow control inserts with different outer profiles to pass by on their way to another housing located at a lower place in the production string 110.
FIG. 2 is a section view of the wellbore 100 of FIG. 1 showing upper housing 200 (first housing) in greater detail. At each end is a threaded connection 115 permitting the upper housing 200 to be installed in the production string 110 at a predetermined location below and above adjacent wellbore elements in a wellbore string. Each upper or first housing includes a first tubular housing side port portion 216 including a number of ports (e.g., 120, extending between and inner surface and an outer surface of the upper (first) housing) that initially permit fluid communication between an interior of the housing and the isolated annular area 212 created between the upper and lower packers 205, 210. The packers are typically the type run in to the wellbore with production string and then remotely actuated after the string is installed. In one embodiment, the packers have elements that are expandable outwardly to contact and seal a space between the packer and the wellbore 100 wall.
An inner profile 215 (constituting a first tubular housing key receiving engagement portion 217) formed in the upper housing 200, is constructed to have a first tubular housing insert spring loaded key element engaging contour on an inner surface of the first tubular housing which is arranged to mate with spring loaded mating keys formed on an wellbore flow control insert to be installed prior to treating the upper zone.
FIG. 3 is a partial section view of the wellbore 100 showing the upper housing 200 of FIG. 2 and also illustrating the delivery of a lower wellbore flow control insert 350 through the bore of the upper housing 200. The wellbore flow control inserts (e.g., 250, 350) are run in to the production string on their own string 125 of tubulars. In the embodiment shown, the run in string 125 is coiled tubing, but the wellbore flow control inserts could be run in on any type of string (including wireline) that allows a tool like the wellbore flow control insert be run in to a wellbore, disconnected from the string and left downhole to be utilized in an operation and then be removed at a later time. Each wellbore flow control insert includes a set of spring loaded keys (e.g., 260, 360) having key profiles formed thereon for mating with a particular housing. In the example shown in FIG. 3, the profiles formed on the spring-loaded keys 360 of the lower wellbore flow control insert do not fit the inner profile 215 formed on the interior surface of the upper housing 200. Consequently, the lower wellbore flow control insert 350 moves downwards (shown by arrow 101) through upper housing 200 with no engagement or interference between the potentially corresponding profiles of the keys and inner surface of the upper housing 200.
FIG. 4 is a view, partially in section, showing the lower housing 300 and the lower wellbore flow control insert 350 installed in the lower housing 300. As shown, the profiles on the spring-loaded keys 360 have found mating profiles (e.g., 315) in the lower housing 300, permitting the spring-loaded keys 360, urged by springs 361 (not shown) to extend outwards and into the lower housing inner profile 315. In particular, the lower wellbore flow control insert 350 is prevented from further downward movement by shoulders 366, 371 formed on the spring-loaded keys 360 and lower housing 300. In the installed position of FIG. 4, apertures 355 formed in the lower wellbore flow control insert 350 are positioned to provide fluid communication from an interior of the housing to the ports 320 formed in the lower housing 300 via an annular space 330 between the lower wellbore flow control insert 350 and the lower housing 300.
FIG. 5 is a section view of the wellbore 100 showing the upper wellbore flow control insert 250 installed in the upper housing 200. The spring-loaded keys 260 (each having a plurality of springs 261 therein) with their outwardly facing profiles are mated with profiles of the housing, preventing downward movement of the wellbore flow control insert due to the interfering shoulders 266, 271. With the lower wellbore flow control insert 350 installed, the run in string 125, visible in FIG. 4, has been removed through the use of a remotely actuatable latch (not shown) typically operable with rotation of the run in string.
Each wellbore flow control insert includes a ball sleeve flow control insert plug and in FIG. 5, upper ball sleeve flow control insert plug 280 of upper wellbore flow control insert 250 is shown in its initially side port closed position. In the side port closed position, the walls of the upper ball sleeve flow control insert plug 280 block a fluid path that would otherwise permit fluid communication between an interior (an upper insert bore 255) of the upper wellbore flow control insert 250 and the upper zone 202 via apertures 155, annular space 130, ports 120 and the upper isolated annular area 212 between upper and lower packers (not shown). O-ring seals 145 positioned in O-ring grooves in a first tubular housing outer surface side port upper sealing portion 148 of the upper tubular wellbore flow control insert 250 and a first tubular housing outer surface side port lower sealing portion 149 of the upper tubular wellbore flow control insert, and O-ring seals 147 positioned in an upper tubular ball sleeve flow control insert plug outer surface side port upper sealing portion 150 and an upper tubular ball sleeve flow control insert plug outer surface side port lower sealing portion 151 are used to seal between the upper housing 200 and wellbore flow control insert 250 and between the upper wellbore flow control insert 250 and the upper ball sleeve flow control insert plug 280.
The upper ball sleeve flow control insert plug 280 is retained in its initial closed position by an upper shear pin 142 temporarily anchoring the sleeve to the upper wellbore flow control insert 250. Formed in a lower end of the sleeve is a ball seat 281 constructed and arranged to receive a ball of predetermined diameter while permitting balls of a smaller diameter to pass through the wellbore flow control insert without being “caught” by the ball seat. Once a ball is seated in the ball seat 281, a fluid path through the sleeve is blocked and fluid pressure can be applied to the ball and ball seat in order to shear the shear pin 142 and move the sleeve to a lower “open” position. Shear pins are commonly used to temporarily hold a movable downhole component in an axial position but any number of devices can be used and are well known in the art, requiring only that movement of the component selectively possible from the surface of the well.
In FIG. 5, a smaller diameter ball 375 is shown passing through the larger diameter ball seat 281 of the upper wellbore flow control insert 250. The movement of the smaller diameter ball 375 is shown by directional arrow 102. By using balls and ball seats of different diameters, the ball sleeves of the various wellbore flow control inserts (e.g., 250, 350) can be opened sequentially, permitting selective operation to be performed on certain zones. In FIG. 5, for instance, the smaller diameter ball 375 is shown moving through the larger diameter ball seat 281 of the upper wellbore flow control insert on its way to a wellbore flow control insert at a lower place in the production string with a mating-sized ball seat. Shown in dashed lines is a larger diameter ball 275 which, when dropped from the surface, will be caught by the larger diameter ball seat 281 of the upper wellbore flow control insert 250, permitting the upper ball sleeve flow control insert plug 280 to be moved to an open position. Disposed in an interior of the wellbore flow control insert is a spring-loaded flapper 140 that is biased toward a closed position. The flapper is held in its initial, open position due to a shoulder 141 formed at an upper end of the upper ball sleeve flow control insert plug 280 whereby, as the sleeve moves downward, a spring-loaded flapper 340 will close (FIG. 7). In the embodiment shown, the central bore through the insert is sealed with a ball and ball seat but it is contemplated that sealing the bore could be performed any number of ways so long as the sealing is remotely accomplished and the bore is initially open.
FIG. 6 is a section view of the wellbore 100 illustrating the lower wellbore flow control insert 350 disposed in the lower housing 300 and showing a lower ball sleeve flow control insert plug 380 in its initial closed position where it is retained by a lower shear pin 342. The lower ball sleeve flow control insert plug includes a smaller diameter ball seat 381, and the smaller diameter ball 375 is shown above the seat with its direction of movement shown by arrow 102. As with the upper sleeve and wellbore flow control insert, the lower ball sleeve flow control insert plug 380 is in a position whereby a fluid path between the interior of the wellbore flow control insert and the lower zone 302 is blocked.
FIG. 7 is a section view of the components of FIG. 6 and illustrates the lower ball sleeve flow control insert plug 380 as it moves between its initial closed position to an open position. As shown, the smaller diameter ball 375 is seated in the smaller diameter ball seat 381 of the ball sleeve. Pressure is being exerted, typically from the surface of the well, and the lower shear pin 342 has been sheared due to the downward force of the fluid pressure on the ball and seat. The movement of the ball sleeve flow control insert plug 380 is shown by arrow 103 as it moves downwards in the lower wellbore flow control insert 350 towards a stop 143 designed to stop its downward movement. The spring-loaded flapper 340 is shown in its closed position with its outer edge in contact with a downwardly facing shoulder 146. The movement of the flapper is shown by arrow 104. As shown, the downward movement of the lower ball sleeve flow control insert plug 380 serves to unblock the apertures 355 formed in the lower wellbore flow control insert 350.
FIG. 8 is a section view of the wellbore 100 showing the lower wellbore flow control insert 350 and lower housing 300 with the lower ball sleeve flow control insert plug 380 in the open position and a “treatment” of the lower zone 302 in progress. As shown, the ball sleeve flow control insert plug is in its open position with downward movement prevented by the stop 143. While the smaller diameter ball 375 seals a lower end of the wellbore flow control insert, a fluid path is opened from an interior of the wellbore flow control insert through the apertures 355, the annular space 330, and the ports 320 into the isolated annular area 312 adjacent the lower zone 302. The treatment material, in one embodiment, is steam injected from the surface and its migration to the zone is illustrated by arrows 105. While steam is used in the embodiment show, it will be understood that water or any other fluid or gas, like CO2 could be injected using the methods and apparatus described herein.
FIG. 9 is a section view of the wellbore 100 showing the production of hydrocarbons through the upper housing 200 and upper wellbore flow control insert 250 from an upper zone 202 as well as from zones below the upper housing 200. Arrows 106 illustrate the movement of the production fluid from the zone utilizing the fluid path permitted by the ports and apertures, and arrows 107 show the movement of fluid below the zone as it flows upwards through the ball seat 281. Larger diameter ball 275, previously seated, has been displaced upwards in the wellbore flow control insert. The spring-loaded flapper 140, in its closed position, permits the ball from moving out of the wellbore flow control insert while permitting the fluid flow through it due to apertures 144 formed in its surface.
The forgoing arrangement is useful in a number of ways. In one embodiment the wellbore flow control inserts are installed one-at-a-time and that zone is treated with steam. Thereafter, another wellbore flow control insert at another location is installed and the zone treated. In another example, multiple wellbore flow control inserts are installed and then the zones are treated in a top down fashion with the balls of different diameter as discussed herein. In one example, the zones are treated at a point wherein the well has essentially stopped producing. After treatment, the zones treated produce for some amount of time without the need for further tooling or intervention. Thereafter, the zones can be re-treated or the wellbore flow control inserts can be removed and replaced by fresh ones prior to another round of steam injection.
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.
Patent Grant
9856718
