Extraction of heat energy from active hydrocarbon wells
By installing a heat exchanger tubing loop in active hydrocarbon wells and circulating a heat exchange fluid, thermal energy is extracted efficiently and cost-effectively, addressing the economic challenges of maintaining abandoned wells and leakage prevention.
Patent Information
- Application Number
- US19/059842
- Authority / Receiving Office
- US · United States
- Patent Type
- Applications(United States)
- Current Assignee / Owner
- Priority Date
- 2024-02-21
- Filing Date
- 2025-02-21
- Publication Date
- 2025-08-21
AI Technical Summary
Existing methods for extracting geothermal energy from abandoned hydrocarbon wells are costly and require active maintenance to prevent hydrocarbon leakage, making them economically unviable.
A process involving running a heat exchanger tubing loop into an active hydrocarbon production or injection well, securing it with a packer or anchor, and circulating a heat exchange fluid to extract thermal energy, which can be done with minimal disruption to well operations.
This method allows for the efficient extraction of thermal energy from active hydrocarbon wells at low installation and ongoing costs, without affecting well operations, by utilizing the heat from produced fluids or formation temperatures.
Smart Images
Figure US20250264251A1-D00000_ABST
Abstract
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which claims benefit under 35 USC § 119 (e) to U.S. Provisional Application Ser. No. 63 / 556,260 filed Feb. 21, 2024 entitled “EXTRACTION OF HEAT ENERGY FROM ACTIVE HYDROCARBON WELLS,” which is incorporated herein in its entirety.STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH
[0002] None.FIELD OF THE INVENTION
[0003] This invention relates to the extraction of geothermal energy from an active hydrocarbon production or injection well.BACKGROUND OF THE INVENTION
[0004] Systems exist for extracting geothermal energy from bore holes. A deep bore hole is drilled to access a region where the temperature is substantially greater than average surface temperature. A heat exchange fluid is passed down the bore hole where its temperature is raised before being circulated back to the surface where the high temperature fluid may be used, e.g. to heat a home.
[0005] It has been suggested that this method could be used to extract heat energy from abandoned hydrocarbon wells, which are very deep and therefore provide access to rock at a high temperature. A problem with this concept is that abandoned hydrocarbon wells are required to be plugged to avoid the possible escape into the environment of hydrocarbon fluids. Maintaining an un-plugged well, especially an offshore well, would require active steps to prevent leakage of hydrocarbons, e.g. maintaining the well under pressure. This is associated with a cost that may not be justified simply by the extraction of thermal energy. Examples of proposals for extraction of energy from abandoned wells are described in NO20210956A1 (Oktra AS), US2013300127A1 (DiNicolantonio) and US2015330670A1 (Wynn).BRIEF DESCRIPTION OF THE DISCLOSURE
[0006] The invention more particularly includes a process for extracting thermal energy from an active hydrocarbon production or injection well, wherein the process comprises:
[0007] a) running a loop of heat exchanger tubing into the active well, e.g. on coil tubing;
[0008] b) securing the heat exchanger tubing;
[0009] c) circulating heat exchange fluid through the heat exchanger tubing; and
[0010] d) extracting thermal energy from the heat exchange fluid at the surface.
[0011] In this way it is believed that useful thermal energy may be extracted from an active hydrocarbon production well or injection well at relatively low installation cost and low ongoing running cost, whilst not substantially affecting the ongoing operation of the well either in producing hydrocarbons or injecting water to stimulate hydrocarbon production.
[0012] One way of achieving this may be for coil tubing to be run into production tubing of a production well, where the coil tubing also carries the loop of heat exchanger tubing. A packer or anchor device may be run into the well to secure the heat exchanger tubing in the production tubing, above the downhole safety valve (DHSV). The packer may be a flow-through packer.
[0013] Above the depth of the DHSV, the formation temperature may not be considerably higher than surface temperature, but fluids coming up from the reservoir are likely to be at much higher temperatures and heat from these fluids by be extracted via the het exchange tubing.
[0014] The installation may involve running the heat exchanger tubing loop into the well and running the packer or anchor device into the well may be achieved on the same coil tubing run as another operation related to hydrocarbon production, thereby further reducing the add-on cost of installing the heat exchange system.
[0015] If the active well is an injector well, a kickoff (that is to say, a window in the production tubing and casing) may be made in the well prior to delivery of heat exchanger tubing through the kickoff and then anchored in a sidetrack well. In this way, the heat of the formation may be directly accessed by the heat exchange tubing.
[0016] Alternatively, the heat exchanger tubing may be anchored outside production tubing and run into the well with the production tubing. In this event the heat exchanger tubing may be anchored much further down the well, below the DHSV, where reservoir and fluid temperatures may be higher. In this situation, the heat exchanger tubing would normally be run into the well during completion of the well.
[0017] At the surface, depending on the temperature of the returned heat exchange fluid, heat may be extracted using a conventional heat exchanger or by a heat pump.
[0018] It may be possible for differences in density of the heat exchange fluid as it is heated and cooled to create circulation or assist circulation of the heat exchange fluid.
[0019] The invention also encompasses a system for extracting thermal energy from an active hydrocarbon production or injection well, wherein the system comprises:
[0020] a) a coil tubing delivery system including a length of coil tubing;
[0021] b) a length of heat exchanger tubing of smaller diameter than the coil tubing;
[0022] c) an assembly mounted on the coil tubing, the assembly including a packer (e.g. a flow-though packer) and a fastener for securing the heat exchanger tubing to the packer;whereby a loop of the heat exchanger tubing is capable of being run into a well on the coil tubing, the packer anchored in the well and the coil tubing then withdrawn.
[0023] Examples and various features and advantageous details thereof are explained more fully with reference to the exemplary, and therefore non-limiting, examples illustrated in the accompanying drawings and detailed in the following description. Descriptions of known starting materials and processes can be omitted so as not to unnecessarily obscure the disclosure in detail. It should be understood, however, that the detailed description and the specific examples, while indicating the preferred examples, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions and / or rearrangements within the spirit and / or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.
[0024] As used herein, the terms “comprises,”“comprising,”“includes,”“including,”“has,”“having” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, product, article, or apparatus that comprises a list of elements is not necessarily limited only those elements but can include other elements not expressly listed or inherent to such process, process, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).
[0025] The term substantially, as used herein, is defined to be essentially conforming to the particular dimension, shape or other word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder.
[0026] Additionally, any examples or illustrations given herein are not to be regarded in any way as restrictions on, limits to, or express definitions of, any term or terms with which they are utilized. Instead these examples or illustrations are to be regarded as being described with respect to one particular example and as illustrative only. Those of ordinary skill in the art will appreciate that any term or terms with which these examples or illustrations are utilized encompass other examples as well as implementations and adaptations thereof which can or cannot be given therewith or elsewhere in the specification and all such examples are intended to be included within the scope of that term or terms. Language designating such non-limiting examples and illustrations includes, but is not limited to: “for example,”“for instance,”“e.g.,”“In some examples,” and the like.
[0027] Although the terms first, second, etc. can be used herein to describe various elements, components, regions, layers and / or sections, these elements, components, regions, layers and / or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the present inventive concept.
[0028] The term “active” in the context of a hydrocarbon production well is used herein to mean a well from which hydrocarbons are being produced or a well that has not been permanently abandoned for the purpose of extracting hydrocarbons. The term “active” in the context of an injection well is used herein to mean a well through which fluids are being introduced into a subterranean hydrocarbon reservoir either continuously or intermittently, or a well that has not been permanently abandoned for this purpose.DETAILED DESCRIPTION OF THE DRAWINGS
[0029] A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings in which:
[0030] FIG. 1 is a schematic view of an offshore hydrocarbon platform showing the invention in use;
[0031] FIG. 2 is a schematic view of a bottom hole assembly at the distal end of a length of coil tubing, showing a first embodiment of the invention;
[0032] FIG. 3 is a view similar to FIG. 2, showing a second embodiment of the invention;
[0033] FIG. 4A is a view similar to FIGS. 2 and 3, showing a third embodiment of the invention; and
[0034] FIG. 4B is a cross section through a production tubing joint for use in the third embodiment.DETAILED DESCRIPTION
[0035] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
[0036] FIG. 1 shows in highly schematic form an offshore hydrocarbon producing platform 1.
[0037] The platform includes an accommodation block 2, which is heated by a conventional circulating hot water system (not shown). The hot water system is a closed loop system and one part 3 of the circuit passes through a heat exchanger 4 located on the platform. The heat exchanger 4 is designed to transfer thermal energy from a portion 5 of heat exchanger tubing 6.
[0038] A loop of the heat exchanger tubing 6 passes from the heat exchanger 4 through a Xmas tree 7 on the platform 1 and down through production tubing 8 of a producing hydrocarbon well. The production tubing passes through a casing 9 (or riser) through the sea surface 10 and into the seabed. Details such as a seafloor template, wellhead and casing strings, etc., are conventional and are omitted from the drawings for clarity. The well could alternatively be an injector well.
[0039] The heat exchanger tubing 6 is anchored at a point in the production tubing. The heat exchanger tubing 6 could be run into this location and installed using coil tubing, according to techniques well known in this art. Alternatively, the heat exchanger tubing 6 could be installed at a point in the annulus A; in this case the heat exchanger tubing could be run in and installed during completing after traditional drilling.
[0040] Above the downhole safety valve (DHSV) the temperature of the rock will be a little higher than at the surface but the produced oil flowing up the tubing will be at a considerably higher temperature because it will have come from a much deeper part of the well. This temperature could be in the region of 80 to 100° C. since temperature down a well may increase by approximately 30 degrees C. per thousand feet of depth.
[0041] Heat exchange fluid is pumped by means of pump 12 located on the platform down one branch of the loop of heat exchanger tubing to the point where the tubing 6 is anchored, and the fluid then returns to the surface via the other branch of the loop and passes again through the heat exchanger 4 and pump 12. The heat exchange fluid may be brine, water, ethanol, an ethanol solution in water, e.g. 35% ethanol in water, or any other suitable fluid. The fluid may contain a biocide and / or an anti-freeze additive.
[0042] The heat exchange fluid is heated by thermal conduction from the oil in the production tubing when fastened inside production tubing. In an alternative arrangement, the heat exchanger tubing may be installed in the annulus during completion after traditional drilling. In this arrangement, the heat exchanger tubing may extend further into the well since it does not have to pass through the DHSV since it is in the annulus. At greater depth, the fluid in the annulus is likely to be at relatively high temperature and so may also transfer heat to the heat exchanger tubing 6 in the annulus.
[0043] In either of the above scenarios, direct heat exchange may be possible between the heat exchange fluid and the water in the tubing 3 of the accommodation block's heating system. If the temperature of the heat exchange fluid is lower for some reason, then a heat pump system may be used to extract thermal energy from the heat exchange fluid. A heat pump is not shown in the drawings but is in itself conventional and would replace the heat exchanger 4 in FIG. 1.
[0044] Of course, the heated water of the heating system may, as is conventional, also be used to heat a hot water supply for washing, etc., by transferring heat via a further heat exchanger to the hot water supply or to any other systems on the platform that require heat.
[0045] FIG. 2 illustrates, again in highly schematic form, the delivery and anchoring of the heat exchanger tubing 6 in the production tubing above the DHSV. A primary barrier element need not be added because the system is above the DHSV and the heat exchanger tubing will come to the platform through the X-mas tree (that is the secondary barrier).
[0046] Coil tubing 13 is run into the production tubing 8 by conventional means, e.g. using a specialist coil tubing vessel or an arrangement on the platform. At the distal end of the coil tubing is an assembly 14.
[0047] The assembly 14 comprises a specially designed flow through packer 16 on a running tool 17. The packer 17 comprises a ring with grips 18 spaced around it on the outer side of the ring. On the inner side of the ring is a fastener 19 that secures a loop of heat exchanger tubing 6 to the packer 16.
[0048] When a workover or drilling operation using coil tubing is to be performed in a well, a specialist vessel or arrangement on the platform is brought in to perform the operation. In addition to performing the required operation, a relatively short coil tubing trip can be made to install the packer 16 at a point in the production tubing above the downhole safety valve (DHSV) 21. Heat exchanger tubing 6 is run into the well alongside the coil tubing. In an alternative embodiment, the heat exchanger tubing is delivered inside the coil tubing to protect it from damage; however, the principles are essentially the same.
[0049] Once the assembly 14 has been delivered to the required depth above the DHSV 21, the packer 16 is set by causing spring loaded grip elements 18 to bear outwardly against the inner surface of the tubing 8. This could be achieved, e.g. by passing a signal to the packer via pulses in drilling fluid. Once the packer 16 is set, the running tool 17 is disengaged with the packer 16 via detachable mountings 20; again, this step can be activated, e.g., in response to a pulsed signal in drilling fluid.
[0050] Once the packer 16 is set, the coil tubing 13 is withdrawn leaving the loop of heat exchanger tubing 6 secured to the packer 16. Because of the design of the packer 16, the tubing is still open and production is substantially unimpaired. The heat exchanger tubing 6 has very small diameter compared to the production tubing and so does not materially affect production rates. The heat exchanger tubing may have a diameter of between 0.25 and 0.75 inches, for example.
[0051] In an alternative embodiment, shown in FIG. 3, heat exchanger tubing may be installed in a water injector well. A kickoff shown generally at 122 is created at a point above the DHSV 121 by known means which will not be described in detail here. A dissolvable whipstock 123 is installed as part of the process of creating the kickoff; windows 124, 125 are created in the tubing 108 and casing 127, respectively, and a short, open hole, sidetrack well 126 bored into the rock 128.
[0052] Coil tubing 113 is then run into the well and diverted by the whipstock 123 into the sidetrack 128. At the distal end of the coil tubing is a packer 116 mounted to a running tool 117. Heat exchanger tubing 106, fastened to the packer 116, is run into the well with the coil tubing 113. The coil tubing and running tool117 is then withdrawn, leaving the packer 116 and heat exchange tubing 106 in place.
[0053] This way of installing heat exchanger tubing could in fact be used for an injector well or a production well, in each case to get the heat from outside the casing. This system will require a primary barrier element and a secondary barrier element because the completion will go through the production liner and conductor / casing. These barriers are not shown in FIG. 3, but it is well-known how to achieve these barriers.
[0054] As with the first embodiment, an option may be to run the heat exchanger tubing inside the coil tubing to protect it whilst running into the well.
[0055] Once the kickoff has been created and the heat exchanger tubing installed, the whipstock 123 may be dissolved by conventional methods, e.g. by delivering acid into the well, and then the injector well may continue to function normally.
[0056] Since the kickoff is created above (proximal of) the DHSV 121, which is normally located a few hundred feet into the well, the temperature of the rock may not be dramatically higher than the ground temperature at the surface. It may be, perhaps 15° C. higher. However, the use of a heat pump at the surface instead of a conventional heat exchanger would still allow this heat energy to be extracted and used.
[0057] FIG. 4A shows a third embodiment, in which heat exchanger tubing 206 is located in the annulus 232 between the production tubing 208 and casing 227. The heat exchanger tubing 206 is retained by a heat exchanger tubing anchor 219 mounted on the outside of the production tubing 208 during completion of the well.
[0058] This installation will be part of the completion of a traditional drilled well. The completion will provide a secondary barrier element in annulus A, but does not need to provide a primary barrier element if it's in the reservoir.
[0059] In this embodiment, there is no need for the heat exchanger tubing to terminate above the DHSV since the heat exchanger tubing is outside the production tubing. In FIG. 4A, the heat exchanger tubing is shown extending to a point just above the production packer 231. The hydrocarbon stream in the production tubing 208 and also the fluid in the annulus 232 will be at a considerably higher temperature than the surface, e.g. 100° C., so transfer of heat to the heat exchange fluid is likely to be more efficient than in the other embodiments. Alternatively, in this embodiment, the heat exchanger tubing can also go through the production packer and down into the reservoir.
[0060] In the third embodiment, the heat exchanger tubing 206 is run into the well with the production tubing 208, the end of the tubing 206 being secured by the anchor 219 as the production tubing 208 is run in. The heat exchanger tubing may also secured by fastening bands to the production tubing at intervals along its length, although this may not be necessary.
[0061] The anchor 219 may be provided as part of a dedicated production tubing joint that comprises an outer tube 233 that encloses the production tube 208 itself and also a smaller diameter heat exchanger tube 234. This arrangement is shown in FIG. 4B. The heat exchanger tubing anchor (not shown in FIG. 4B) is also located for protection between the outer tube 223 and the production tube 208. This arrangement is similar to a known arrangement for a chemical injector valve. The tubing can also be attached to the production tube with specially made clamps.
[0062] In the third embodiment, the heat exchange system is installed at the start of the life of the well, in the completion stage. By installing the heat exchange system in the annulus of the well rather than inside the casing, it is protected from production equipment, logging tools and other treatments inside the casing. Unfortunately access to the annulus may be hindered by completion and the heat exchange system may be cemented in place. In contrast, in the first and second embodiments the heat exchanger tubing may be installed as a retro-fit at any time in the life of the well.
[0063] In any of the embodiments described above, especially the first and third since the temperatures are higher, it may be possible to use the effect of heat on the density and / or phase of the heat exchange fluid to cause it to flow round the loop. For example, the heat exchanger tubing may be formed from concentric tubes with the inner tubing feeding down into the well and the outer tube leading out of the well. Since the fluid in the outer tube will have more thermal energy transferred to it, its density will be less than that of the incoming fluid in the central tube. Depending on the fluid and the temperature, it may be that the fluid in the outer tube is vaporized at least for part of its journey back to the surface. This may promote circulation of the fluid and may assist or even replace the pump 12.
[0064] The above embodiments have been described with reference to an offshore well, but there is no reason why a slightly modified system could not be used to extract thermal energy from an onshore well since the principles are the same.
[0065] It is envisaged that heat energy extracted from an active hydrocarbon well on one platform or in one location may be transferred for use on other platforms or installations, e.g. offshore wind farms, or even to onshore installations.
[0066] The techniques described in the embodiments above for installing heat exchanger tubing in a well either in production tubing or an annulus, could equally be applied to wells where the wellhead is installed on the seafloor in a subsea template, rather than on a platform. Produced hydrocarbons from such subsea wells are piped to the surface at another location, e.g. a platform or an onshore location. If the length of the pipeline is relatively short, then the temperature of the hydrocarbons may be substantially maintained. If the pipeline runs for a long distance and / or if it is running though deep / cold water then the pipeline may be heated, for example using direct electrical heating, to maintain efficient flow. In either case, the heat exchanger tubing from the subsea well template could be attached to the pipeline and run to the same platform or onshore location as the pipeline, where the thermal energy from the heat exchange fluid in the tubing could be employed in the same way as discussed above in connection with embodiments one to three,
[0067] In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as a additional embodiments of the present invention.
[0068] Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.REFERENCES
[0069] All of the references cited herein are expressly incorporated by reference. The discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication data after the priority date of this application. Incorporated references are listed again here for convenience:
[0070] NO20210956A1 (Oktra AS), “System and method for geothermal power production.”
[0071] US2013300127A1 (DiNicolantonio), “Geothermal energy recovery from abandoned oil wells.”
[0072] US2015330670A1 (Wynn), “System and Method for Utilizing Oil and Gas Wells for Geothermal Power Generation.”
Claims
1. A process for extracting thermal energy from an active hydrocarbon production or injection well, wherein the process comprises:a) running a loop of heat exchanger tubing into the active well;b) securing the heat exchanger tubing;c) circulating heat exchange fluid through the heat exchanger tubing; andd) extracting thermal energy from the heat exchange fluid at the surface.
2. The process according to claim 1, wherein the heat exchanger tubing is run into the well using coil tubing.
3. The process according to claim 2, wherein the coil tubing is run into production tubing of a production well, and the coil tubing also carries the loop of heat exchanger tubing.
4. The process according to claim 1, wherein a packer or anchor device is run into the well to secure the heat exchanger tubing in the production tubing, above a downhole safety valve.
5. The process according to claim 4, wherein the packer is a flow through packer.
6. The process according to claim 4, wherein running the heat exchanger tubing loop into the well, running the packer or anchor device into the well and the operation related to hydrocarbon production are all performed on the same run of coil tubing.
7. The process according to claim 1, wherein the active well is an injector well and wherein a kickoff is made in the well prior to delivery of heat exchanger tubing through the kickoff and then anchored in a sidetrack well.
8. The process according to claim 1, wherein the heat exchanger tubing is anchored outside production tubing and is run into the well with the production tubing.
9. The process according to claim 8, wherein the heat exchanger tubing is run to a point in the well deeper than a downhole safety valve in the production tubing.
10. The process according to claim 8, wherein the heat exchanger tubing is run into the well during completion of the well.
11. The process according to claim 1, wherein a heat pump is used to transfer thermal energy from the heat exchange fluid at the surface.
12. The process according to claim 1, wherein differences in density of the heat exchange fluid as it is heated and cooled create circulation or assist circulation of the heat exchange fluid.
13. The process according to claim 1, wherein the active well is a subsea well having a wellhead located on the seafloor, and wherein the heat exchanger tubing is brought to the surface at a location remote from the subsea well.
14. The process according to claim 13, wherein the remote location is a marine installation such as a marine platform or an onshore location, and wherein produced hydrocarbons are transported by pipeline to the location and the heat exchanger tubing is run along the pipeline.
15. The process according to claim 14, wherein the pipeline is a heated pipeline.
16. A system for extracting thermal energy from an active hydrocarbon production or injection well, wherein the system comprises:a) a coil tubing delivery system including a length of coil tubing;b) a length of heat exchanger tubing of smaller diameter than the coil tubing;c) an assembly mounted on the coil tubing, the assembly including a packer and a fastener for securing the heat exchanger tubing to the packer;whereby a loop of the heat exchanger tubing is capable of being run into a well on the coil tubing, the packer anchored in the well and the coil tubing then withdrawn.
17. The system according to claim 16, wherein the packer is a flow-through packer.
18. The system according to claim 16, wherein the loop of the heat exchanger tubing is mounted in the coiled tubing, adjacent the coiled tubing, or in the annulus of the casing.
19. The system according to claim 16, wherein the active well is a subsea well having a wellhead located on the seafloor, and wherein the heat exchange tubing is brought to the surface at a location remote from the subsea well.
20. The system according to claim 19, wherein the remote location is a marine installation such as a marine platform or an onshore location, and wherein produced hydrocarbons are transported by pipeline to the location and the heat exchange tubing is run along the pipeline, optionally wherein the pipeline is a heated pipeline.