Patent Application
20120298356
Some hydrocarbon formations accessed by wellbores do not have adequate natural pressure to cause the hydrocarbons to rise to the surface on their own. In these wells, artificial lift systems can encourage production for such formations. For example, pumps used in the wellbore or at the well's surface can produce fluids to the surface, or gas injection into the wellbore can lighten the weight of fluids and facilitate their movement towards the surface.
In other techniques, a compressible fluid, such as pressurized steam, is injected into the wellbore or an adjacent wellbore to improve production. This is especially useful in a producing field having formations with heavy oil because the heat and pressure of the injected steam reduces the viscosity of oil.
To perform steam injection, operators isolate zones of interest at different depths in the wellbore with packers and then inject steam into the wellbore to the zones. Because each wellbore includes production zones with varying natural pressures and permeability, the amount of injected steam can vary between zones.
Although separate conduits can be used between the injection source and each zone, operators preferably use a single toolstring to carry the steam to the multiple zones. For example,
The mandrels 50 have one or more nozzles 60 that inject steam from the tubing string 20 to the zones of interest. Packers 26 isolate each zone to ensure that steam leaving the mandrel's nozzles 60 travels thorough the adjacent perforations 14 in the casing 12 to the desired zones. At the surface, surface equipment 30 controls injection pressures, injection rates, and steam quality during the steam injection operations.
The tool 50 has a tubular body 52 with apertures 54 for passage of steam. A sleeve 56 disposed on the body 52 contains the steam, which is directed to nozzles 60 on the end of the sleeve 56. Each nozzle 60 injects a predetermined amount of the steam into the wellbore, and this amount is determined in part by the supply pressure at the surface and the characteristics of the nozzles 60. An extension 70 conveys additional steam not passing through the apertures 54 further downhole from the tool 50 to other tools on the toolstring (20;
Once the wellbore 10 of
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.
A dual-purpose tool and method can be used for steam injection and production in a wellbore on the same toolstring. A mandrel disposed on the toolstring deploys in the wellbore to communicate steam into the wellbore annulus in a steam injection operation. The mandrel can remain deployed in the wellbore to then communicate production fluid from the wellbore to the surface during production operations. In general, the tool can be run in any type of wellbore, including open or cased holes, and it can even be deployed inside tubing, a slotted liner, or the like.
A distributor on the mandrel separates inner and outer manifolds. The inner manifold transfers steam from within the mandrel's bore to the distributor and transfers production fluid in the reverse. The outer manifold transfers the steam from the distributor to the wellbore annulus and transfers production fluid in the reverse.
The distributor controls the flow of steam and production fluid between these inner and outer mandrels. To do this, nozzles on the distributor inject the steam from the inner manifold into the wellbore annulus. Additionally, production valves on the distributor produce the production fluids from the wellbore annulus into the tool. For the outer manifold, a screen can be used to screen production fluids before they are produced through the production valves. The nozzles can also allow production fluids to flow through them and into the mandrel. Alternatively, backflow valves can be used with the nozzles to prevent or restrict the flow of production fluids through the nozzles while still permitting the flow of steam out of the nozzles.
In one arrangement, a dual-purpose steam injection and production apparatus for a wellbore has a mandrel, a distributor, and a screen. The mandrel deploys in the wellbore and communicates steam and production fluid. The distributor and screen are disposed on the mandrel. The distributor permits fluid communication of the steam out of the mandrel and permit fluid communication of the production fluid into the mandrel, while the screen at least screens fluid communication of the production fluid into the distributor.
To inject steam with the apparatus, for example, the distributor can have nozzle that permits fluid communication of the steam out of the mandrel and preferably controls the flow of steam. In some implementations, the nozzle can permit fluid communication of the production fluid into the mandrel, or the nozzle can have a backflow valve that prevents fluid communication of the production fluid through the nozzle.
To produce fluid with the apparatus, the distributor can have a flow valve that prevents fluid communication of the steam out of the mandrel, but permits fluid communication of the production fluid into the mandrel. Both the nozzle and the flow valve can be used on the same distributor member, they can be used independently on separate distributor members, or they can be used together on separate distributor members.
For its part, the screen can be used to screen production fluid entering through just the nozzles, through just the production valves, or through both. In general, the screen can have a sleeve with one or more orifices communicating with the distributor and can have a screen element disposed on the sleeve adjacent the one or more orifices.
The mandrel can have inner and outer bodies. The inner body defines a bore and has at least one port communicating the bore outside the inner body. The outer body is disposed on the inner body and communicates the at least one port with the distributor.
The apparatus can be disposed on a toolstring deploying in the wellbore, and at least one isolation element can isolate portions of the wellbore annulus. In this way, steam injection and production operations deploy the apparatus in the wellbore. When the at least one isolation element is set, steam is injected from the nozzle on the apparatus into the wellbore. When production operations commence, production fluid from the wellbore is screened into the apparatus. This can be done without the need to run another toolstring.
In another arrangement, a dual-purpose steam injection and production apparatus for a wellbore has a mandrel and a distributor, but may or may not have a screen. As before, the mandrel deploys in the wellbore and communicates steam and production fluid. The distributor disposed on the mandrel has at least one nozzle and at least one flow valve. The nozzle permits fluid communication of the steam out of the mandrel. The flow valve, however, prevents fluid communication of the steam out of the mandrel and permits fluid communication of the production fluid into the mandrel.
The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.
A dual-purpose tool 100 in
Although one tool 100 is shown, it will be appreciated that steam injection and production operations can use a number of such tools 100 disposed along the toolstring. Moreover, additional components, such as thermal packers, cup packers, expansion joints, and the like, will also be used on the toolstring as will be understood. For example, the toolstring may have thermal packers with integral expansion joints or may have thermal cup packers with separate expansion joints located between injection zones to isolate them from one another. Moreover, surface equipment known in the art can control injection pressures, injection rates, and steam quality and handle production of produced fluids.
Turning to the tool 100 in more detail, the tool 100 has a mandrel 102 with a distributor 108 disposed between an inner manifold 104 and an outer manifold 106. The mandrel 102 conveys steam and fluids through the tool 100. The inner manifold 104 transfers the steam and fluids within the tool 100, while the outer manifold 106 transfers the steam and fluid between the tool 100 and the wellbore annulus. For its part, the distributor 108 controls the flow of the steam and fluids between the two manifolds 104 and 106.
Looking first at the inner manifold 104, an outer sleeve 120 is disposed on an inner body 110 so that an annular space 122 is formed therebetween. Ports 114 along the inner body 110 communicate the body's bore 112 with this annular space 122 so injected steam or produced fluids can pass therebetween. The size, number, and arrangement of these ports 114 are selected to provide critical flow for steam injection as well as to facilitate the flow of production fluids and can vary depending on the implementation.
Steam conveyed down the inner body 110 can pass through the ports 114 and into the annular space 122. In a reverse manner, production fluid in the annular space 122 can pass through the ports 114 and into the inner body's bore 112 to be conveyed uphole in the mandrel 105. One end of the annular space 122 is closed by an end cap 124 disposed on the sleeve 120 and body 110.
For the distributor 108, a distributor cap 130 is disposed between the inner and outer manifolds 104 and 106 and exchanges steam and fluid between the manifolds 104 and 106. The distributor cap 130 has channels 134 defined about an inner passage 132. The channels 134 communicate with the annular space 122 between the inner manifold's bodies 110 and 120. However, the cap's inner passage 132 communicates with the inner body 110 so its bore 112 can communicate with a tubular extension 170, which connects further downhole to additional components (e.g., another tool or additional tubular).
The nozzles 140 and production valves 150 on the distributor cap 130 communicate the inner manifold's space 122 with the outer mandrel's space 162 between the tubular extension 170 and a screen 160. Affixed to the distributor cap 130 and disposed along the extension 170, this screen 160 allows steam and fluid to flow through it and separates the nozzles 140 and valves 150 from the downhole wellbore annulus surrounding the tool 100.
When the tool 100 is deployed downhole for a steam injection operation, injected steam passes through the inner body's bore 112, and some of the steam exits the ports 114 into the bodies' annulus 122 of the inner manifold 104. (Additional steam can bypass the mandrel's ports 114 and pass through the extension 170 to further downhole portions of the toolstring.)
In the annular space 122, the injected steam contained by the sleeve 120 then exits the nozzles 140 into the annular space 162 between the extension 170 and screen 160. At this point, the injected steam passes through the screen 160 to treat the formation in the surrounding wellbore annulus. As noted previously, this injected steam can reduce the viscosity of heavy oil, which can facilitate production during later operations.
As detailed later, the nozzles 140 are preferably venturi-style nozzles designed to maintain critical flow of the injected steam according to the purposes of the steam injection operation. All the while, however, the production valves 150 restrict fluid flow of the steam in the manifold space 122 from passing through them. This can help ensure that a proper number of exits for the injected steam provided by the nozzles 140) is used to inject the steam so that critical flow, quality, and other desirable features of the steam injection operation can be maintained.
Once steam injection is complete, the tool 100 can then be used for production without the need to remove the tool 100 from the wellbore. Because clogging from production fluids can be a concern, the screen 160 filters the production fluid from the wellbore annulus as it enters the tool 100. For this reason, the screen 160 can be particularly suited to meet and filter the expected sands, fines, and other particles to be encountered downhole in the particular wellbore. Once filtered by the screen 160, the production fluid passes from the screen annulus 162, through the nozzles 140, and into the inner manifold's space 122. Likewise, to increase the flow area through the distributor cap 130, the production valves 150 open in response to reverse pressure from the production fluid and permit the screened fluid to enter the inner manifold's space 122. Once in the manifold 104, this production fluid can pass through the ports 114 and into the tool's bore 112 to be produced at the surface.
As will be appreciated, the steam injection operation must maintain pressures, temperatures, rates, and quality of the steam as it is delivered downhole and injected through the various tools 100 for the operation to be beneficial. Loss of any of these desired characteristics of the steam may prevent an adequate application of pressure and temperature to the zones of interest. As noted herein, these considerations require certain sizes and number of ports 114, certain numbers of nozzles 140, and certain shapes of those nozzles 140 to accomplish the necessary results.
Unfortunately, simply producing fluid back through the ideal configuration for steam injection may cause clogging and/or limited production of production fluid. For this reason, the disclosed tool 100 balances the two opposing operations of steam injection and production in the same tool 100 so that the goals of both operations can be achieved. As noted previously, such has not been the case in the prior art, where separate toolstrings are used for the separate operations.
With an understanding of the tool 100 and how it can be used for the dual purposes of injecting steam and producing fluid in a wellbore, discussion now turns to some particulars of the tool's components.
Starting from the uphole end of the tool 100A, the end cap 124 welds to the inner manifold's sleeve 120 and the tubular body 110, and the tubular body 110 and the sleeve 120 weld to the distributor cap 130. The extension 170 attaches or welds to the other side of the distributor cap 130, and the various nozzles 140 and valves 150 thread into the distributor cap's channels 134.
As shown in
Here at the outer mandrel 106, the screen 160 includes an outer sleeve 164 with a number of radial orifices 165 and includes a screen member 166 disposed about this outer sleeve 164 and covering the orifices 165. Steam in the annular space 162 between the outer sleeve 164 and extension 170 can pass out the orifices 165 and through the screen element 166 to the wellbore annulus. Similarly, production fluids can pass through the screen element 166 and orifices 165 and into the annular space 162. Other assemblies for the screen 160 disclosed herein could be used, including, but not limited to, a well screen, a sand control screen, a gravel pack screen, a wire-wrapped screen, a mesh screen, an expandable sand screen, an inflow control device (ICD), a slotted liner, a perforated pipe, and combinations thereof. Moreover, more than one screen 160 can be used on the tool 100A, and a given screen 160 can have more than one section of orifices 165 and screen elements 166 other than as shown.
Turning to
During steam operations, steam contained in the annular space 122 of the inner manifold 104 can pass through the distributor cap's channels 132, through the nozzles 140, and into the space 172 between the extension 170 and intermediate sleeve 135. During reverse flow from production, however, production fluid contained in this space 172 can pass through the nozzles 140 and into the mandrel's annular space 122.
Each nozzle 140 defines a venturi-style passage 142 having a throat 144. The contour of this passage 142 and its throat 144 are designed to recover pressure of the steam contained in the inner space 122 so the tool 100A can achieve a more constant rate of steam for the operation with less pressure differential during the steam injection. In particular, the amount of steam entering downhole zones during steam injection can be difficult to control because any zones with higher natural pressure or lower permeability may not receive enough steam. Therefore, a critical flow of steam preferably passes through the nozzles 140 so sufficient steam can be applied to the zones of interest.
During critical flow, the sonic velocity of the compressible steam's flow through at least one location of the nozzle 140 is preferably equal to the speed of sound of the fluid at local fluid conditions. In other words, the Mach number of the fluid is preferably 1.0 at the throat 144 (or smallest restriction) of the nozzle 140. To attain this critical flow, the nozzles 140 should maintain a preferred ratio of pressures between the wellbore annulus and the toolstring. In some cases, the preferred ratio is at least greater than 0.56. (Additional details of how the nozzle 140 is designed can be found in U.S. Pat. No. 6,708,763, which is incorporated herein by reference in its entirety.)
Looking at the production valve 150 shown in detail in
During steam injection, pressure from the steam enters the proximal end 151b of the valve 150 from the inner manifold 104. The steam acts against the ball 154, pushing it along with the bias of the spring 156 against the seat 152. The seating of the ball 154 in this way prevents the injected steam from passing out of the valve 150 during steam operations. Instead, injected steam can only pass through the nozzles (140) so that the steam injection can be controlled as noted previously.
During backflow as shown in
The first tool 100A discussed above in
In
In another difference, this tool 100B restricts flow of the production fluid through the nozzles 140, rather than letting production fluid pass from the screen 160 and through the nozzles 140 as with the previous tools. In particular, backflow valves 180 install on the nozzles 140. During steam injection, the backflow valves 180 permit steam to flow out of the nozzles 140. During production, however, the backflow valves 180 restrict production fluid from flowing into the nozzles 140. This can avoid issues of the nozzles 140 clogging with production fluid.
Further details of this tool 1008 are shown in
Various valve types can be used for the backflow valve 180 on the nozzles 140. As shown in
During steam injection when steam enters the valve's proximal end 181b, pressure from the steam moves the dart 184 away from the seat 182 against the bias of the spring 186. With the dart 184 moved, steam can pass through flow passages 185 in the dart 184 and out the nozzle 140.
In the absence of steam, the dart 184 seats. During production, production fluid pressure entering the nozzle 140 and the valve's distal end 181a acts against the seated dart 184, which further seats it. This prevents reverse flow through the nozzle 140 and valve 180 so that the nozzle 140 is less likely to become clogged during production.
In some implementations, issues with clogging and the need for increased flow of production fluid may present less of a problem so that production valves 150 may not be needed on the tool 100. For example,
In other implementations, issues with clogging may present less of a problem so a screen (160) may not be needed on the tool 100. Yet, increased flow of production fluid may still be needed. Therefore, a fourth configuration of a dual purpose tool 100D of
In
In each of the previous tools 100, the nozzles 140, production valves 150, and screen 160 have been disposed toward one end of the mandrel 102—namely, toward the downhole end. The reverse arrangement can alternatively be used depending on the implementation so the components of nozzles 140, production valves 150, and/or screen 160 can be disposed toward an uphole end of the mandrel 102. Moreover, a split configuration can be used as discussed below.
As shown in
Extensions 170A-B extend opposite one another from the distributor caps 130A-B to attach to other components.
The outer manifold sections 106A-B include one screen member 160B provided for the tool 100E at the end having the production valves 150. If production fluid is intended to enter the tool 100E through the injection valves 140, then another screen member 160A can be provided for the other manifold section 106A at the end of the tool 100E having the injection nozzles 140 as shown.
Although not shown, both distributor caps 130A-B could each have a combination of nozzles 140 and production valves 150. Alternatively, no screen member may be used on one or both of ends of the tool 100E. As shown in
Just a few dual-ended tools have been shown in
With the benefit of the present disclosure and these examples, it will be appreciated that these and other combinations can be provided. In general then, either of the distributor caps 130A-B for a dual-ended tool can have a combination of nozzles 140, production valves 150, and/or backflow valves 180. Moreover, either of the outer manifold sections 106A-B can have or not have screen members 160.
The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. Several configurations for the disclosed dual-purpose tool have been described and shown in the Figures. With the benefit of the present disclosure and its teachings, the features and components of one configuration can be combined with those of another configuration to produce additional configurations within the spirit of the present disclosure.
In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.
