SW-SAGD with between heel and toe injection

Abstract

Single well SAGD is improved by having one or more injection segments and two or more production segments between the toe end and the heel end of a flat, horizontal well. The additional injection points improve the rate of steam chamber development as well as the rate of production, as shown by simulations of a central injection segment bracketed by a pair of production segments (-P-I-P-), and by a pair of injection segments with three production segments (-P-I-P-I-P). Although the completion of the single well costs more, this configuration allows the development of thin plays that cannot be economically developed with traditional SAGD wellpairs.

Claims

1. A method of producing heavy oil from a reservoir by single well steam and gravity drainage (SW-SAGD), said method comprising: a) providing a horizontal well (not a wellpair) below a surface of a reservoir, said horizontal well being fitted for steam injection along its horizontal length; b) said horizontal well having a toe end and a heel end and a middle therebetween at 25-75% of well length; c) injecting steam into said horizontal length of said horizontal well for a start-up period of time until a steam chamber develops over said horizontal length; d) after developing said steam chamber, converting said horizontal length of said horizontal well to have one or more injection segments and two or more production segments between said toe end and said heel end, wherein each injection segment is separated from an adjacent production segment by a packer and a blank joint lacking any holes or a sliding sleeve; and e) injecting steam into said injection segments and simultaneously producing mobilized heavy oil from said two or more production segments; f) wherein said method produces more oil at a time point than a similar SW-SAGD well with steam injection only at a toe end of said similar SW-SAGD well.

2. The method of claim 1, wherein an injection point is at said middle at 45-55% of said well length.

3. The method of claim 1, wherein two injection points are at about ½ and ¾ of the horizontal length of said well.

4. The method of claim 1, wherein injected steam includes solvent.

5. The method of claim 1, wherein said method includes a cyclic preheating phase comprising a steam injection period along an entire length of the well followed by a soaking period.

6. The method of claim 5, including two cyclic preheating phases.

7. The method of claim 5, including three cyclic preheating phases.

8. The method of claim 7, wherein said soaking period is 10-30 days.

9. The method of claim 7, wherein said soaking period is 20 days.

10. A method of producing heavy oil from a reservoir by single well steam and gravity drainage (SW-SAGD), said method comprising: a) providing a horizontal well (not a wellpair) below a surface of a reservoir; b) said horizontal well being flat and having a toe end and a heel end and a middle therebetween at 25-75% of well length; c) said horizontal well having one or more injection segments and two or more production segments between said toe end and said heel end, wherein each injection segment is separated from an adjacent production segment by a blank joint lacking any holes and a flow control device; and d) injecting steam into said injection segments and simultaneously producing mobilized heavy oil from said two or more production segments; e) wherein said method produces more oil at a time point than a similar SW-SAGD well with steam injection only at a toe end of said similar SW-SAGD well; f) wherein said method includes a preheating phase comprising a steam injection period along an entire horizontal length of said horizontal well until a steam chamber forms over said entire horizontal length before converting said horizontal well to have one or more injection segments and two or more production segments.

11. The method of claim 10, wherein an injection point is at said middle at 45-55% of said well length.

12. The method of claim 10, wherein two injection points are at about ¼ and ¾ of a horizontal length of said well.

13. The method of claim 10, wherein injected steam includes solvent.

14. The method of claim 10, wherein said converting comprises closing packers positioned between said injection segment(s) and said production segment(s).

15. The method of claim 10, wherein said converting comprises adding packers between said injection segment(s) and said production segment(s).

16. The method of claim 10, wherein said method includes a cyclic preheating phase comprising a steam injection period along said entire length followed by a soaking period.

17. The method of claim 16, including two cyclic preheating phases.

18. The method of claim 16, including three cyclic preheating phases.

19. The method of claim 18, wherein said soaking period is 10-30 days.

20. The method of claim 18, wherein said soaking period is 20 days.

21. A method of producing heavy oil from a reservoir by single well steam and gravity drainage (SW-SAGD), said method comprising: a) providing a horizontal well (not a wellpair) below a surface of a reservoir, said horizontal well being fitted for steam injection along its horizontal length; b) said horizontal well having a toe end and a heel end and a middle therebetween at 25-75% of well length; c) injecting steam into said horizontal length of said horizontal well for a start-up period of time until a steam chamber develops over said horizontal length; d) after developing said steam chamber, converting said horizontal length of said horizontal well to have one or more injection segments and two or more production segments between said toe end and said heel end, wherein each injection segment is separated from an adjacent production segment by one or more packer(s) and sliding sleeve(s); e) injecting steam into said injection segments and simultaneously producing mobilized heavy oil from said two or more production segments; f) moving said sliding sleeve(s) and repeating step e; and g) optionally repeating step f; h) wherein said method produces more oil at a time point than a similar SW-SAGD well with steam injection only at a toe end of said similar SW-SAGD well and wherein less oil is lost behind a blind interval than a similar method without said sliding sleeve(s).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1A shows traditional SAGD wellpair, with an injector well a few meters above a producer well.

(2) FIG. 1B shows a typical steam chamber.

(3) FIG. 2A shows a SW-SAGD well, wherein the same well functions for both steam injection and oil production. Steam is injected into the toe (in this case the toe is updip of the heel), and the steam chamber grows towards the heel. Steam control is via packer.

(4) FIG. 2B shows another SW-SAGD well configuration wherein steam is injected via ICCT, and a second tubing is provided for hydrocarbon removal.

(5) FIG. 3 illustrates center point injection SW-SAGD (CPSW-SAGD).

(6) FIG. 4A is multi-point injection SW-SAGD (MPSW-SAGD). One injection point is situated at ¼ well length from the heel and the other is ¾ well length from the heel, and each steam chamber grows in both directions, meeting in the middle of the well.

(7) FIG. 4B and FIG. C show sliding sleeve use, wherein the sliding sleeves are moved in 4C to uncover some of the blind spots in 4B and allow more oil production. Note these figures are not drawn to scale, and due to size constraints only a small amount of movement (one hole) is shown. Significant additional movement is possible though, especially when combined with packer opening/closing and/or movement or addition of packers and/or FCD use.

(8) FIG. 4D is similar to 4A, but complete tubing is used for production and injection, as opposed to the bypass production tubing shown in FIG. 4A.

(9) FIG. 5 shows simulated oil saturation profiles of (A) conventional SW-SAGD, (B) SW-SAGD with center injection point (half of full well length shown), and (C) SW-SAGD with two injection points (quarter of full well length shown) after 3 years of steam injection. All simulations performed with CMG-STARS using a fine grid block.

(10) FIG. 6 shows simulated temperature profiles of (A) conventional SW-SAGD, (B) CPSW-SAGD with center injection point (half of full well length shown), and (C) MPSW-SAGD with two injection points (quarter of full well length shown) after 3 years of steam injection.

(11) FIG. 7 shows a comparison of oil production rate. Note that the End-Injector case is conventional SW-SAGD, the Center-Injector case is CWSW-SAGD with a center injection point, and the Two-Injector case is MPSW-SAGD with two injection points spaced for equally sized steam chambers.

(12) FIG. 8 is a comparison of oil recovery using the same three well configurations as in FIG. 7.

DESCRIPTION OF EMBODIMENTS

(13) The present disclosure provides a novel well configurations and method for SW-SAGD.

(14) This novel modification to the conventional single-well SAGD (SW-SAGD) process varies the location and number of steam injection points during the production phase, and the same points can be used in preheat or cyclic preheat.

(15) The conventional SW-SAGD process grows a steam chamber and drains oil by gravity by utilizing one single horizontal well with steam injected only at the toe and liquid produced through the rest of the well. SW-SAGD has potential to unlock vast thin-zone (<5-20 meter pay) oil sand resources where SAGD using well pairs is economically and technically challenging.

(16) However, the conventional SW-SAGD normally suffers from slow steam chamber growth and low oil production rate as the steam chamber can only grow from toe gradually towards the heel. This is ineffective, and seriously limits the usefulness of SW-SAGD.

(17) In this invention, we propose an improved SW-SAGD process with one or more steam injection points between the toe and heel end. For example, a center steam injection point can be used, or multiple steam injection points spaced for equal steam chamber development can be used to significantly accelerate steam chamber growth and oil recovery. The superior recovery performance of the proposed configuration and methods is confirmed by our simulation results.

(18) It is surprising that this elegant solution to the low production level issue with SW-SAGD has never been proposed before. However, one reason is that most SAGD simulations are either run as 2D cross-sections, or as 3D models with relatively large gridding in the wellbore direction (typically 25-100 m), both of which will either eliminate the “end effect” (in the case of 2D simulations), or seriously under-estimate it (in the case of large-block 3D simulations). Thus, given the tools typically available to the petroleum engineer, even if the idea was attempted, traditional models would not show any benefit.

Conventional SW-SAGD

(19) The conventional SW-SAGD utilizes one single horizontal well to inject steam into reservoir through toe and produce liquid (oil and water) through mid and heel of the well, as schematically shown in FIGS. 2A and B. A steam chamber is expected to form and grow from the toe of the well. Similar to the SAGD process, the oil outside of the steam chamber is heated up with the latent heat of steam, becomes mobile, and drains with steam condensate under gravity towards the production portion of the well. With continuous steam injection through toe and liquid production through the rest of the well, the steam chamber expands gradually towards the heel to extract oil.

(20) Due to the unique arrangement of injection and production, the SW-SAGD can also benefit from pressure drive in addition to gravity drainage as the recovery mechanisms. Also, compared with its counterpart, the traditional dual well or “DW-SAGD” configuration, SW-SAGD requires only one well, thereby saving almost half of well cost. SW-SAGD becomes particularly attractive for thin-zone applications where placing two horizontal wells with the typical 4-10 m vertical separation required in SAGD is technically and economically challenging.

(21) SW-SAGD, however, exhibits several disadvantages leading to slow steam chamber growth and low oil rate. First of all, SW-SAGD is not efficient in developing the steam chamber. The steam chamber growth depends largely upon the thermal conduction to transfer steam latent heat into cold reservoir and oil drainage under gravity along the chamber interface. Due to the arrangement of injection and production points in the conventional SW-SAGD, the steam chamber can grow only direction towards the heel. In other words, only one half of the surface area surrounding the steam chamber is available for heating and draining oil. Secondly, a large portion of the horizontal well length perforated for production does not actually contribute to oil production until the steam chamber expands over the whole length. This is particularly true during the early stage where only a small portion of the well close to the toe collects oil. Third, toe oil may be lost as the toe is fitted only for injection, not production.

CPSW-SAGD

(22) To overcome the aforementioned issues associated with the conventional SW-SAGD, we propose steam injection in between the heel and toe to improve the recovery performance at about the center of the well. By “center” herein, we refer to roughly the center of the longitudinal portion of the well, and do not consider the vertical portion. By doing this, the steam chamber can grow in both directions from roughly the middle. The essential idea is to allow full development of steam chamber from both sides and increase the effective production well length earlier in the process.

(23) FIG. 3 shows schematically a simple, but effective (as demonstrated later by simulation) process modified from the conventional SW-SAGD, in which the steam injection point is placed in the middle of the horizontal well. The toe and heel sections of the horizontal well, isolated from the steam injection portion by thermal packers (indicated by the boxes with the X therein) within the wellbore, are perforated and serve as producer to collect heated oil and condensed water.

(24) As illustrated in FIG. 3, the steam chamber can now grow from both sides, with the effective thermal and drainage interfaces virtually doubled. Consequently, the effective production well length is doubled, resulting in a significant uplift in oil production rate.

MPSW-SAGD

(25) To further improve the performance SW-SAGD, multiple steam injection points can be introduced into the wellbore to initiate and grow a serial of steam chambers simultaneously. FIG. 4 gives an example with two injection points, one at ¼ well length from the heel and the other ¾ well length from the heel. The SW-SAGD with multiple steam injection points can significantly accelerate the oil recovery by engaging more well length into effective production. With two injection points as placed in FIG. 4, the dual steam chambers will each grow in both directions, and meet in roughly the middle of the well.

(26) The number of the steam injection points and intervals between them non rally need to be determined and optimized based on the reservoir properties and economics. It is worth pointing out that implementing multiple steam injection points within a single wellbore adds complexity to the wellbore design and consequently well cost, necessitating the providing of multiple injections points and additional packers. Nevertheless, the proposed invention presents a considerable potential for improving SW-SAGD applications to thin-zone bitumen reservoirs.

Steam Chamber Simulations

(27) To evaluate the performance of the proposed modification to the conventional SW-SAGD, numerical simulation with a 3D homogeneous model was conducted using Computer Modeling Group® Thermal & Advanced Processes Reservoir Simulator, abbreviated CMG-STARS. CMG-STARS is the industry standard in thermal and advanced processes reservoir simulation. It is a thermal, k-value (KV) compositional, chemical reaction and geomechanics reservoir simulator ideally suited for advanced modeling of recovery processes involving the injection of steam, solvents, air and chemicals.

(28) The reservoir simulation model was provided the average reservoir properties of Athabasca oil sand, with an 800 m long horizontal well placed at the bottom of a 20 m pay. The simulation considered three cases, the conventional SW-SAGD, CPSW-SAGD with centered injector, and MPSW-SAGD with two injectors (one 200 m and the other 600 m from heel). A smaller than usual grid size was modeled in order to capture the effects (e.g., 1-5 m, preferably 2 m). No startup period was modeled. The modeled operational conditions, including pressure and injection rates, were similar to a typical SAGD operation.

(29) FIGS. 5 and 6 show the simulated profiles of oil saturation and temperature after 3-year steam injection for the three cases. Note that due to element of symmetry, the case of the SW-SAGD with centered injection point only shows one half of the well length and the case of the SW-SAGD with two injection points shows a quarter of the well length.

(30) For the conventional SW-SAGD, the steam chamber extends to about ⅓ of the well length, leaving ⅔ of the well length not in production. The case with centered steam injection point results in steam chamber development over half of the well length and the case with two injection points show the steam zone over almost 80% of the well length. Thus, simply moving the steam injection point to the middle of the well, and by adding more than one injection point, the steam zone can cover the entire well.

Production Simulations

(31) In order to prove the benefit of the CPSW-SAGD and MPSW-SAGD we performed production simulations, also using CMG-STARS. FIG. 7 compares the oil production rate of the three cases from above.

(32) Surprisingly, the oil production rate is almost doubled from the conventional SW-SAGD by placing the injection point in the middle of the well, and is further lifted by 50% when two injection points are implemented.

(33) The oil rate drop at 1600 days in the case with two injection points is due to the steam chamber coalescence. With two injection points, two steam chambers develop that are separated from each other at the beginning. As steam injection continues, both steam chambers will grow vertically and laterally. Depending on the distance between the two steam injection points, the edges of the two steam chambers will eventually meet somewhere in the mid-point, in a phenomena called “coalescence” of the steam chamber. The sum of surface area of the two chambers is larger before coalescence than after coalescence, because one of the boundaries is shared after coalescence. The heating of oil and resulting oil drainage depends on the surface or contact area. Therefore, it is typical that the oil rate drops when the steam chamber coalescences.

(34) FIG. 5 shows the comparison of the oil recovery factor, which again illustrates the significant improvement of the described invention over the conventional SW-SAGD.

(35) We have not yet run a simulation case with 3 injection points, but we expect even faster oil recovery. It is predicted that the wells can thereby be longer to fully realize the benefits of three injection points. Additional injection points can be added, particularly for longer lengths, but costs of completion will also increase, and thus optimization based on permeability, pressure, thickness of the pay, etc. is preferred.

(36) The simulated payzone was big at 20 m. However, the relative gain really comes from the surface area increase due to doubling size of the incipient steam chambers. Thus, even with a thinner pay zone, we still expect the same relative performance improvement.

(37) The following references are incorporated by reference in their entirety for all purposes. Falk, K., et al., Concentric CT for Single-Well Steam Assisted Gravity Drainage, World Oil, July 1996, pp. 85-95. McCormack, M., et al., Review of Single-Well SAGD Field Operating Experience, Canadian Petroleum Society Publication, No. 97-191, 1997. Moreira R. D. R., et al., IMPROVING SW-SAGD (SINGLE WELL STEAM ASSISTED GRAVITY DRAINAGE), Proceedings of COBEM 2007 19th International, Congress of Mechanical Engineering, available online at www.abcm.org.bript/wpcontent/anais/cobem/2007/pdf/COBEM2007-0646.pdf. Faculdade de Engenharia Mecanica, Universidade estadual de Campinas. Sa SPE-59333 (2000) Ashok K. et al., A Mechanistic Study of Single Well Steam Assisted Gravity Drainage. SPE-54618 (1999) Elliot, K., Simulation of early-time response of single well steam assisted gravity drainage (SW-SAGD). SPE-153706 (2012) Stalder, Test of SAGD Flow Distribution Control Liner System, Surmont Field, Alberta, Canada US2012004308 1 Single well steam assisted gravity drainage US520130213652 SAGD Steam Trap Control US20140000888 Uplifted single well steam assisted gravity drainage system and process U.S. Pat. No. 5,626,193 Method for recovering heavy oil from reservoirs in thin formations