The present application is a U.S. National Stage Application of International Application No. PCT/US2015/018772 filed Mar. 4, 2015, which is incorporated herein by reference in its entirety for all purposes.
This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides a flow control device for injecting steam into a subterranean formation and producing hydrocarbons from the same subterranean formation.
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation typically include a number of different steps such as, for example, drilling a wellbore at a desired well site, treating the wellbore to optimize production of hydrocarbons, and performing the necessary steps to produce and process the hydrocarbons from the subterranean formation.
In some subterranean formations, the hydrocarbons are difficult to recover because they are trapped in shale or because the hydrocarbons are not very viscous, e.g., where the hydrocarbons are in the form of tar. In such formations, the formation needs to be treated to make the hydrocarbons more viscous so that they can be produced to the surface. One such technique is to inject steam into the formation to make the hydrocarbons more viscous.
One way of doing this is to drill two horizontal wells into the formation with one well drilled above the other well. Steam is injected into the top well and allowed to permeate through the formation. The hydrocarbons which have become more viscous due to their exposure to the steam are then produced through the bottom well. This technique is commonly known as the Steam Assisted Gravity Drainage (SAGD) method.
Another way of injecting steam into the formation to make the hydrocarbons more viscous is to inject the steam into the formation through a single well. With this technique, the steam may be injected into the formation for long periods of time, for example, six months. Then, once the hydrocarbons have reached a certain viscosity, they are produced through the same well. This technique is known as a Huff & Puff well and used in Canada and other places were tar sands are prevalent. The advantage of a Huff & Puff well is that only one well needs to be drilled.
The present disclosure is directed to an improved device and method for enhancing production from Huff & Puff wells, although as those of ordinary skill appreciate other applications of the device and method disclosed herein may exist.
For a more complete understanding of the present disclosure and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:
Representatively illustrated in
Thus, the properties and problems associated with steam injection and subsequent liquid water production in formations are fairly well known in the art. However, it should be clearly understood that the principles of the present disclosure are not limited in any way to the use of water as the injected and/or produced fluid.
Examples of other suitable fluids include hydrocarbons such as naphtha, kerosene, and gasoline, and liquefied petroleum gas products, such as ethane, propane, and butane. Such materials may be employed in miscible slug tertiary recovery processes or in enriched gas miscible methods known in the art.
Additional suitable fluids include surfactants such as soaps, soap-like substances, solvents, colloids, or electrolytes. Such fluids may be used for or in conjunction with micellar solution flooding.
Further suitable fluids include polymers such as polysaccharides, polyacrylamides, and so forth. Such fluids may be used to improve sweep efficiency by reducing mobility ratio.
Therefore, it will be appreciated that any fluid or combination of fluids may be used in addition, or as an alternative, to use of water. Accordingly, the term “fluid” as used herein should be understood to include a single fluid or a combination of fluids, in liquid and/or gaseous phase.
As discussed above, the water is typically injected into the formation after the water has been heated sufficiently so that it is in its gaseous phase. The water could be in the form of superheated vapor (as shown at point A in
In some examples described below, it is desired that the water produced from the formation be in its liquid phase, so that the water changes phase within the formation prior to being produced from the formation. In this manner, damage to the formation, production of fines from the formation, erosion of production equipment, etc., can be substantially reduced or even eliminated.
However, it is also desired that this phase change take place just prior to production of the water from the formation, so that heat energy transfer from the steam is more consistently applied to the formation, and while the steam is more mobile in the formation, prior to changing to the liquid phase. Thus, in the phase diagram of
Referring additionally now to
Specifically, the detail depicts an example in which flow of the fluid (in this example, water) is controlled so that it is injected into the formation at a pressure and temperature corresponding to point C in the gaseous phase, and is produced from the formation at a pressure and temperature corresponding to point F in the liquid phase. Point F is on a curve G which is just above, and generally parallel to, the phase change curve E. In other examples, the fluid could be injected at any of the other points A, B, D in
Preferably, the fluid is produced at a point on the phase diagram which is on the curve G, or at least above curve G. Thus, the curve G represents an ideal production curve representing a desired phase relationship or phase state at the time of production. Stated differently, curve G represents a maximum temperature and minimum pressure phase relationship relative to the liquid/gas phase change curve E.
Note that such phase-based flow control of the fluid cannot be based solely on temperature, since at a same temperature the fluid could be a gas or a liquid, and the flow control cannot be based solely on pressure, since at a same pressure the fluid could also be a gas or a liquid. Instead, this disclosure describes various ways in which the flow control is based on the phase of the fluid.
In examples described below, various flow control devices can be used in well systems to obtain a desired injection of steam and production of water and then hydrocarbons, but it should be understood that this disclosure is not limited to these examples. Various other benefits can be derived from the principles described below. For example, the flow control devices can be used to provide a desired quantitative distribution of steam along an injection wellbore, a desired quantitative distribution of water along a production wellbore, a desired temperature distribution in a formation, a desired steam front profile in the formation, etc.
Representatively illustrated in
The flow control device 11 fits over a mandrel 12 formed with one or more ports 14 disposed around its circumferential surface. The mandrel 12 can be production tubing or casing, as shown in
The piston 20 has a solid body portion 22 and a flanged portion 24. The solid body portion 22 is formed with one or more ports 26 formed through the radial thickness of the body. The one or more ports 26 correspond generally in number and size to the ports 14 in the mandrel 12 and the ports 18 in the housing 16. The flanged portion 24 of the piston 20 has an inner flange 28, which is disposed adjacent to the outer wall of the mandrel 12 and an outer flange 30, which disposed adjacent to the inner wall of the housing 16. The inner flange 28 has one or more ports 32 disposed around the circumferential surface of the piston 20. The number of ports 32 corresponds to a flow restriction that creates enough of a pressure drop, at a given flow rate, to enable the production of the liquid and/or hydrocarbon to be adequately balanced along the length of the wellbore; thereby, reducing the heel-toe effect of long wells and/or mitigating the uneven production caused by a heterogeneous reservoir. Also, the ports 32 are in fluid communication with ports 14. The combined ports 32 are generally smaller in size or overall flow area than the combined ports 14, 18 and 26. The smaller ports 32 control the rate at which hydrocarbons are produced to the surface.
The flow control device 11 further includes a bellows 34. The bellows 34 is designed to slide the piston 20 longitudinally along the mandrel 12 and the housing 16 from a first position where the ports 26 in the piston may align with the associated ports 14 in the mandrel 12 and the ports 18 in the housing 16. There is a chamber 36 disposed within the bellows 34 which contains a fluid 38. The bellows 34 is defined by a wall 40 and may also include a biasing device 42 (such as a mechanical spring), which can apply a biasing force to alter the pressure in the chamber 36, as shown in
As the temperature increases and/or the pressure decreases, the flow control device 11 could move to a first position, e.g., to permit relatively unrestricted flow of saturated steam as indicated by arrows A in
The flow control device 11 further includes a filter 44, which is provided to filter out rocks, sand and other debris from the fluids being produced to the surface. The filter 44 may be formed of one or more fine metal screens, but may be formed of any other material capable of being withstanding the harsh downhole environment. Those of ordinary skill in the art will appreciate which types of filters to use for a given application.
Note that, in any of the examples of the flow control device 11 described above, pressure in the chamber 36 can be above or below the liquid-gas phase change curve E of
In some examples, the biasing force can transition between positive and negative. This provides for further fine tuning of the piston's response to changes in pressure, temperature and pressure differential at the flow control device 11.
It may now be fully appreciated that the above disclosure provides significant advances to the art of constructing and operating flow control devices to control a phase of fluid flow in a well. In some examples described above, water 38 is disposed in a chamber 36 having a variable volume. A biasing device 42 reduces or increases the pressure in the chamber 36.
The biasing device 42 may bias the wall 40 of the chamber 36 outward. The biasing device 42 may apply a biasing force which decreases the pressure in the chamber 36. The biasing device 42 may include a classic metal spring in the chamber 36. The biasing device 42 may also include a wall of the chamber 36 (such as, the wall 40 of the bellows 42).
As shown in
Also described herein is a method of controlling the flow of steam and production of hydrocarbons in a well. In one example, the method comprises delivering the flow control device 11 downhole to a region in the subterranean formation containing hydrocarbons, the flow control device 11 being formed of the mandrel 12 and port 14 formed therein, housing 16 disposed around the mandrel 12 having port 18 formed therein, piston 20 formed between the mandrel 12 and the housing 16 having first and second ports 26 and 32, with the first port 26 being larger than the second port 32, and bellows 34 formed between an inner surface of the housing 16 and an outer surface of the piston 20, the bellows having a fluid 38 contained therein; pumping steam down the mandrel 12, the steam warming the fluid 38 in the bellows 34 thereby causing it to expand so that the bellows slides the piston 20 into a first position whereby the first port 26 of the piston aligns with the ports 14 and 18 in the mandrel and the housing, respectively; and injecting the steam into the subterranean formation upon alignment of the first port 26 in the piston 20 and the ports in the mandrel and the housing 14 and 18, respectively.
The method further includes ceasing injection of the steam into the subterranean formation when the hydrocarbons become viscous enough to produce by flowing them through the mandrel to the surface. The method further includes allowing the fluid contained within the bellows to cool thereby causing the bellows to contract so as to move the piston to slide into a second position wherein the second port aligns with the ports in the mandrel and the housing. The hydrocarbons from the subterranean formation flow through the ports in the mandrel, housing and piston and into the mandrel when the piston is in the second position. The method further includes filtering the hydrocarbons of debris before producing them to the surface. As those of ordinary skill will appreciate, water will likely be produced to the surface with the hydrocarbons. The method also may include applying a biasing force to the bellows so as to alter the pressure of the chamber therein. As those of ordinary skill in the art will appreciate, the method can be repeated in different regions of the subterranean formation 54, as illustrated in
Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.
Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.
It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.
Filing Document | Filing Date | Country | Kind |
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PCT/US2015/018772 | 3/4/2015 | WO | 00 |
Publishing Document | Publishing Date | Country | Kind |
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WO2016/140664 | 9/9/2016 | WO | A |
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Entry |
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International Search Report and Written Opinion issued in related PCT Application No. PCT/US2015/018772 dated Oct. 29, 2015, 14 pages. |
Number | Date | Country | |
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20180003019 A1 | Jan 2018 | US |