FLOW CONTROL DEVICES IN SW-SAGD

Abstract

The present disclosure relates to a particularly effective well configuration that can be used for single well steam assisted gravity drainage of SW-SAGD wherein steam flashing through production slots is prevented by included passive inflow control devices or active interval control valves in the completion.

Claims

1) A method of producing heavy oils from a reservoir by single well steam and gravity drainage (SW-SAGD), comprising: a) providing a horizontal well below a surface of a reservoir; b) said horizontal well having a toe end and a heel end and having at least two segments separated by a packer: i) a production segment at said heel end fitted for production, and ii) a injection segment at said toe end fitted for steam injection; c) said horizontal well fitted with a plurality of flow control devices (“FCDs”), said FCD being as passive inflow control device (“ICD”) or an active interval control valve (“ICV”); d) injecting steam into said injection segment to mobilize heavy oil; and e) simultaneously producing mobilized heavy oil at said production segment; f) wherein said method has a lower cumulative steam to oil ratio than the same reservoir developed using a SW-SAGD well without said plurality of FCDs.

2) The method of claim 1, wherein a thermal packer separates said injection segment and said production segment.

3) The method of claim 1, wherein said plurality of FCDs are evenly spaced along the entire well.

4) The method of claim 1, wherein said plurality of FCDs are evenly placed through said second segment and a spacing between FCDs increases towards said heel.

5) The method of claim 1, wherein said FCDs are passive ICDs.

6) The method of claim 1, wherein said FCDs are active ICVs that can be controlled from said surface.

7) The method of claim 1, wherein said injection segment extends upwardly into said reservoir and is above said production segment.

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

9) The method of claim 1, wherein at least one blank pipe section is placed between said injection segment and said production segment.

10) The method of claim 1, wherein a more restrictive ICD in the injection segment than in the production segment of the well.

11) The method of claim 9, wherein a thermal packer is placed in said blank pipe to separate said injection segment and said production segment.

12) The method of claim 1, wherein said method includes a pre-heating phase comprising a steam injection period followed by a soaking period.

13) The method of claim 12, including two cyclic pre-heating phases.

14) The method of claim 12, including three cyclic pre-heating phases.

15) The method of claim 1, wherein said method includes a pre-heating phase comprising a steam injection in both the injection segment and the production segment followed by a soaking period.

16) The method of claim 15, including two cyclic pre-heating phases.

17) The method of claim 15, including three cyclic pre-heating phases.

18) The method of claim 9, wherein said blank pipe is 12-24 meters.

19) The method of claim 9, wherein said production segment is 300-600 meters, said blank pipe is 12-50 meters, and said injection segment is 150-250 meters.

20) The method of claims 12 wherein said soaking period is 10-30 days.

21) The method of claims 12 wherein said soaking period is 20 days.

22) A well configuration for producing heavy oils from a reservoir by single well steam and gravity drainage (SW-SAGD), comprising: a) a horizontal well below a surface of a reservoir; b) said horizontal well having a toe end and a heel end and having at least two segments separated by a packer: i) a production segment at said heel end fitted for production, and ii) a injection segment at said toe end fitted for steam injection; c) said horizontal well fitted with a plurality of passive inflow control devices (ICDs).

23) The well configuration of claim 22, wherein a thermal packer separates said injection segment and said production segment.

24) The well configuration of claim 22, wherein said plurality of ICDs are evenly spaced along the entire well.

25) The well configuration of claim 22, wherein said plurality of ICDs are evenly placed through said second segment and a spacing between ICDs decreases towards said heel.

26) The well configuration of claim 22, wherein said ICDs are passive ICDs.

27) The well configuration of claim 22, wherein active ICDs that can be controlled from said surface are used in place of one or more ICDs.

28) The well configuration of claim 22, wherein said injection segment extends upwardly into said reservoir and is above said production segment.

29) The well configuration of claim 22, wherein at least one blank pipe section is placed between said injection segment and said production segment.

30) The well configuration of claim 22, wherein more than one blank pipe section is placed between said injection segment and said production segment.

31) The well configuration of claim 29, wherein a thermal packer is placed in said blank pipe to separate said injection segment and said production segment.

32) The well configuration of claim 31, wherein said production segment is 300-600 meters said blank pipe is 12-50 meters and said injection segment is 150-250 meters.

33) An improved method of producing heavy oils from a SW-SAGD, wherein steam in injected into a toe end of a horizontal well to mobilize oil which is then produced at a heel end of said horizontal well, the improvement comprising providing a plurality of ICDs in the horizontal well, thus improving a CSOR of said horizontal well as compared to the same well without said plurality of ICDs.

34) An improved method of producing heavy oils from a SW-SAGD, wherein steam in injected into a toe end of a horizontal well to mobilize oil which is then produced at a heel end of said horizontal well, the improvement comprising providing a plurality of passive ICDs or active ICVs in the horizontal well, thus improving a CSOR of said horizontal well, as compared to the same well without said plurality of passive ICDs or active ICVs.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0082] FIG. 1A shows traditional SAGD wellpair, with injector well a few meters above a producer well.

[0083] FIG. 1B shows a typical steam chamber.

[0084] 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.

[0085] FIG. 2B shows another SW-SAGD well configuration wherein steam is injected via CT, and a second tubing is provided for hydrocarbon removal.

[0086] FIG. 3 shows steam cycling at the toe, thus breaking through to the production slots.

[0087] FIG. 4 show one embodiment of the invention wherein SW-SAGD is performed using passive ICDs.

[0088] FIG. 5 shows a comparison of the SW-SAGD cumulative oil recovery of convention SW-SAGD using thermal packers, versus SW-SAGD with passive ICDs. The graph indicates a significant increase in production over a nine year simulation. Computer Modeling Groups' (CMG) STARS thermal simulator was used to perform the analysis.

[0089] FIG. 6 shows a comparison of the CSOR for conventional SW-SAGD using thermal packers, versus SW-SAGD with passive ICDs and packers. As can be seen, the prior art method uses considerable more steam. Computer Modeling Groups' (CMG) STARS thermal simulator was used to perform the modeling.

[0090] FIG. 7A shows a channel type passive ICD.

[0091] FIG. 7B shows a nozzle type passive ICD.

DESCRIPTION OF EMBODIMENTS

[0092] The present disclosure provides a novel well configurations and method for SW-SAGD, wherein passive or active inflow control devices are used together with packers prevent steam break through.

[0093] ICDs are placed at the end of the producer nearest the injector, thus reducing the problem of steam cycling at the toe. However, ICDs can also be placed in the injector portion, thus preventing steam loss even at the toe. Further, if flow control along the producer length is needed, e.g., due to uneven steam chamber development, it is advantageous to place ICDs along the length of the producer.

[0094] Use of ICDs all along the well serves to minimize breakthrough along its entire length, which is particularly beneficial in SW-SAGD since there is no vertical separation between steam injection and production. Thus, this placement is generally preferred.

[0095] Spacing of ICD's may be dictated by reservoir heterogeneity. However, it may also be possible to decrease the spacing of the ICDs towards the heel section, as steam chamber growth tends to be less pronounced at the heel. An ideal spacing may be one device per joint, but more or less can be used, depending on reservoir conditions, and density can be easily varied by varying joint length or by using an ICD every other joint and combinations thereof. Simulations are typically be used to evaluate optimal spacing under reservoir conditions.

[0096] It is also possible to vary the strength of an ICD along the well length. Typically, a more restrictive ICD will be used in the injection section (for instance a 0.4 FRR (Flow Resistance Rating) versus a 1.6 FRR in the production part of the well. Combinations of strength and spacing may also be advantageously employed to control flow along the length of the well.

[0097] ICDs are usually pre-configured on surface and after the deployment, it is not possible to adjust the chokes to alter the flow profile into the well unless a work over is performed where the completion is withdrawn from the well and replaced. When used in a steam injection well, ICDs are able to make more evenly distributed steam injection along the well bore. When used in a SW-SAGD production well, ICDs are able to balance the flow profile along the well and to balance well bore pressure; thus to prevent steam breakthrough and help to achieve steam trap control. They are very beneficial in SW-SAGD where steam breakthrough near the toe presents particular challenges, and where breakthrough all along the well is more prevalent than in conventional SAGD where the steam is injected above the producer. An ICV can be used anywhere an ICD is used, but ICDs may be preferred in some instances as less expensive.

[0098] Stalder investigated the flow distribution control of passive ICDs. Based on the observation of an ICD-deployed SAGD well pair in a Surmont SAGD operation, he came to the conclusion that an ICD-deployed single tubing completion achieved similar or better steam conformance as compared to the standard toe/heel tubing injection. In addition, the ICD completion significantly reduced tubing size which in turn reduced the size of slotted liner, intermediate casing, and surface casing. The smaller wellbore size increases directional drilling flexibility and reduced drag making it easier and lower cost to drill the wells. Thus, wells can be drilled much longer than current SAGD wells, which tend to be between 500 and 1000 m.

ICD Completions

[0099] SW-SAGD wells not only bring advantages, but also present new challenges in terms of drilling, completion and production. One of these challenges is the frictional pressure losses increasing with well length. The inflow profile becomes distorted so that the heel part of the well produces more fluid than the toe when these losses become comparable to drawdown. This inflow imbalance, in turn, often causes premature water or gas breakthrough, which should be avoided.

[0100] Installation of ICDs or ICVs is an advanced well completion option that provides a practical solution to this challenge. An ICD is a well completion device that directs the fluid flow from the annulus into the base pipe via a flow restriction and an ICV is a remote controlled valve.

[0101] The ability of an ICD to equalize the inflow along the well length is due to the difference in the physical laws governing fluid flow in the reservoir and through the ICD. Liquid flow in porous media is normally laminar, hence there is a linear relationship between the flow velocity and the pressure drop. By contrast, the flow regime through an ICD is turbulent, resulting in a quadratic velocity/pressure drop relationship.

[0102] The physical laws of flow through an ICD make it especially effective in reducing the free gas production. In situ gas viscosity under typical reservoir conditions is normally at least an order of magnitude lower than that of oil or water; while in situ gas density is only several times smaller than that of oil or water. Gas inflow into a well will thus dominate after the initial gas breakthrough if it is not restricted by gravity or an advanced completion. ICDs introduce an extra pressure drop that is proportional to the square of the volumetric flow rate. The dependence of this pressure drop on fluid viscosity is weak for channel devices and totally absent if nozzle or orifice ICDs are used. These characteristics enable ICDs to effectively reduce high velocity gas inflow.

[0103] The magnitude of a particular ICD's resistance to flow depends on the dimensions of the installed nozzles or channels. This resistance is often referred to as the ICD's “strength”. It is set at the time of installation and can not be changed without a major intervention to recomplete the well.

[0104] ICDs have been installed in hundreds of wells during the last decade, being now considered to be a mature, well completion technology. Steady-state performance of ICDs can be analyzed in detail with well modeling software. Most reservoir simulators include basic functionality for ICD modeling.

[0105] FIG. 4 shows an exemplary completion using a single well with injector and producer portions separated by thermal packers. Steam breakthrough is prevented with ICDs, especially near the injector producer changeover, thus wasting less steam and more quickly developing the steam chamber.

[0106] FIGS. 5 and 6 show simulation results of a simulated McMurray reservoir using CMS-Stars wherein 200 meters of injector was fitted with 4 ICDs and 800 m of producer was fitted with 20 ICDs and a thermal packer was placed between the two sections. The ICDs were fitted at a spacing of one per joint (˜40 feet), and the tubulars were blank between each ICD. At the injector segment, we had 6 inches of sand screen on about 2% of the well. The producer included 17 ft of screen on each joint. In this case a ICD was modeled based upon the Baker Equalizer, which is a channel type ICD, as shown in FIG. 7A. However, a nozzle type ICD (7B) a combination types are expected to have similar performance improvements. The simulations used porosity=33%, Perm Horizontal=3400 md, Perm Vertical was 680 md, Chamber Pressure=5500 kPa Max and a Wellbore Sub-Cool of 5° C.

[0107] As can be seen, cumulative oil recovery increased with time as compared to the same well lacking the ICDs and the CSOR was significantly reduced. The spike in the CSOR in the conventional SW-SAGD is due to steam loss by breakthrough to the producer, which can be prevented or at least minimized with passive ICDs (FIG. 6). Preventing this steam breakthrough improves the thermal efficiency of the process, keeping heat in the reservoir.

[0108] Temperature profiling was also done (not shown), and over time a more even chamber was formed using the ICDs with 3× cyclic steam preheat.

[0109] The following references are incorporated by reference in their entirety for all purposes.

[0110] Falk, K., et al., Concentric CT for Single-Well Steam Assisted Gravity Drainage, World Oil, July 1996, pp. 85-95.

[0111] McCormack, M., et al., Review of Single-Well SAGD Field Operating Experience, Canadian Petroleum Society Publication, No. 97-191, 1997.

[0112] SPE-59333 (2000) Ashok K. et al., A Mechanistic Study of Single Well Steam Assisted Gravity Drainage.

[0113] SPE-54618 (1999) Elliot, K., Simulation of early-time response of singlewell steam assisted gravity drainage (SW-SAGD).

[0114] SPE-153706 (2012) Stalder, Test of SAGD Flow Distribution Control Liner System, Surmont Field, Alberta, Canada

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