CA2313837C - Positioning of the tubing string in a steam injection well - Google Patents
Positioning of the tubing string in a steam injection well Download PDFInfo
- Publication number
- CA2313837C CA2313837C CA 2313837 CA2313837A CA2313837C CA 2313837 C CA2313837 C CA 2313837C CA 2313837 CA2313837 CA 2313837 CA 2313837 A CA2313837 A CA 2313837A CA 2313837 C CA2313837 C CA 2313837C
- Authority
- CA
- Canada
- Prior art keywords
- steam
- toe
- tubing string
- heel
- well
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
Abstract
A steam-assisted gravity drainage process, involving a co-operating pair of closely spaced, horizontal steam injection and liquid production wells, is modified as follows: .cndot. during the initial circulation phase, the tubing string is landed at the toe of the injection well; and .cndot. during the following injection phase, the tubing string is landed at the heel or intermediate the heel and toe. It has been found that steam preferentially leaks into the reservoir at heel and toe due to pressure drop arising from friction effects through the annulus, between the tubing string and screened liner. So the steam delivery point through the tubing string during the circulation phase is located at the toe, but it is retracted to the heel or to between heel and toe for the injection phase, to shorten the annulus and thereby lessen the pressure drop.
Description
1 "POSITIONING OF THE TUBING STRING IN
2 A STEAM INJECTION WELL"
3 FIELD OF THE INVENTION
4 The present invention relates to managing the location of the delivery point of steam in the injection well of a steam-assisted gravity drainage oil 6 recovery operation.
9 Steam-assisted gravity drainage ("SAGD") is the label used to identify a thermal, two-stage process used in recent years to recover very viscous oil 11 from a subterranean formation or reservoir at shallow depth.
12 The SAGD process was originally developed to recover oil from the 13 McMurray oil sand, in northern Alberta, at depths of about 100 meters or 14 greater.
The oil in this formation is so viscous that it is immobile. It must be 16 heated to reduce its viscosity and increase its mobility, before there is any 17 chance of producing it.
18 The process, as heretofore practised, has involved the following:
19 ~ A pair of wells are drilled down from ground surface and have a horizontal wellbore section completed in the base portion of the 21 reservoir. The horizontal sections of the two wells are parallel and 22 co-extensive. The horizontal section of one well is usually 23 positioned directly above the other, in closely spaced relationship.
24 The upper well is referred to as the steam injection well and the lower well as the production well;
1 ~ Each well has a "heel" (where the downwardly extending wellbore 2 bends to horizontal) and a "toe" (the furthest extremity of the 3 horizontal section);
4 ~ Each well is typically completed with a scxeened sand exclusion liner extending along the length of the horizontal section of the well;
6 ~ Each well is equipped with a string of tubing extending into the 7 horizontal liner;
8 ~ In a first stage of the process, fluid transmissibility is established 9 across the span of formation separating the wells. In some reservoirs, this interwell span is saturated with immobile oil, so that 11 heated oil and steam condensate cannot drain through the span to 12 reach the production well. To achieve transmissibility, the following 13 procedure has successfully been applied in these reservoirs. The 14 tubing string in each well is landed at the toe of the well. Steam is circulated down the tubing and back through the annulus of the well 16 to create two parallel hot elements, which heat the span between 17 them by thermal conduction. Once the oil in the span is sufficiently 18 heated to be mobile, a differential in circulating pressure maintained 19 between the two wells will cause the oil in the span to be displaced into the production well. Steam and steam condensate replaces the 21 displaced oil in the permeable channels extending through the 22 span. When this is achieved, the span is now in condition to enable 23 liquid drainage therethrough. In other reservoirs containing a lighter 24 and more mobile oil, it is only necessary to inject steam through the upper well, with the lower well open, and displace the oil in the span 1 with steam. Again, the span is now in condition to enable liquid 2 drainage therethrough;
3 ~ At this point, the second stage of the process is initiated. The 4 injection well is converted to steam injection, simultaneously through the well annulus and the tubing string. The production well 6 is converted to liquid production. The wells are now ready to work 7 in tandem or to co-operate to recover oil from the reservoir by the 8 mechanism of steam-assisted gravity drainage. Steam is injected 9 through the injection well. The steam rises and heats up the cold oil directly above the injection well. The heated oil and steam 11 condensate drain downwardly through the interwell span to the 12 production well and are produced therethrough to ground surface.
13 Over time, a large oil-depleted chamber is developed, extending 14 upwardly from the pair of co-operating wells, as much of the oil in the section of reservoir overlying the wells is mobilized and 16 produced.
17 When the SAGD process was being initially demonstrated in the field, 18 the length of the horizontal sections of the wells was only in the order of 19 200 meters. It was anticipated that if the horizontal sections were double that length, then the production rates and recovered oil volumes should also 21 double. However, when co-0perating pairs of wells with double the horizontal 22 section length were put into production, it was found that performance did not 23 meet expectations. In fact the production rate and oil recovered was only 24 about 50°r6 greater. It was clear that there was a problem and it was not self-evident what this problem was.
2 The present invention is based on the discovery that, when the tubing 3 string is landed at the toe of the injection well and steam is injected through 4 the annulus and tubing string simultaneously in the second stage of the SAGD
process, the steam predominantly leaks or enters the formation from the well 6 in the areas of the heel and toe. Otherwise stated, steam injection is 7 concentrated at the heel and toe. As a result, there is a likelihood that steam 8 short-circuiting to the production well in one or both of these areas will take 9 place. In addition, much of the oil along the interval between heel and toe will remain unheated and unproduced.
11 The discovery and recognition of the problem arose from an analysis of 12 data from field pilot wells and from subsequent numerical modelling. These 13 investigations indicated:
14 ~ that, if one compares the annulus pressure profiles of the injection and production wells, along the horizontal intervals;
16 ~ then one finds that at the heel and toe areas of the two wells there 17 was a positive pressure differential (that is, the pressure in the 18 annulus of the injection well was greater than that in the annulus of 19 the production well) but I~tween the heel and toe areas, there was a negative pressure differential (that is, the pressure in the annulus 21 of the injection well was less than that in the annulus of the 22 production well); and 1 ~ this was accompanied by a steam leakage profile which showed 2 that steam injection was higher at heel and toe than in between, 3 and a temperature profile which indicated that the temperature in 4 the interwell span was higher at heel and toe than it was in between.
6 It is our belief that these observed results are largely induced by 7 pressure loss experienced by the steam due to friction as it moves along the 8 horizontal wellbore annulus.
9 If there is relatively high steam leakage into the reservoir at the heel and toe areas of the well, then this of course means that there is relatively 11 little heating of the reservoir along the production interval intermediate the 12 heel and toe.
13 In accordance with the invention, the SAGD process has therefore 14 been modified as follows:
~ during the first stage of the process, steam is delivered through the 16 tubing string in the injection well at the heel or at the toe end of the 17 horizontal well section; but 18 ~ during the second stage, steam is injected through both the 19 annulus and the tubing string in the injection well and the steam delivery point of the tubing string is maintained at a point 21 intermediate the heel and toe of the horizontal wellbore section.
22 In a preferred embodiment, we land the end of the tubing string at the 23 toe end of the injection well when establishing transmissibility and retract the 24 string to land its end intermediate the toe and heel during the SAGD stage.
{E3082663.DOC;1 }5 1 By doing this we have achieved the following:
2 ~ the length of the horizontal annulus (the passageway formed 3 between liner and tubing string) has been shortened. The pressure 4 drop per lineal meter in the liner alone is only a fraction of the pressure drop in the annulus between the tubing string and liner.
6 By shortening the horizontal annular space, we have significantly 7 reduced the pressure drop experienced by steam moving along the 8 horizontal section of the well; and 9 ~ we have ensured that the steam issuing from the tubing string is certain to heat the reservoir as it moves between the delivery point 11 and the toe end of the horizontal section.
14 Figure 1 is a schematic showing a pair of horizontal wells for co-operating to carry out the first stage of a SAGD process, the wells each being 16 equipped with a liner and a tubing string; and 17 Figure 2 is a schematic showing the wells of Figure 1 with the tubing 18 string of the injection well re-positioned so that the annulus is shortened.
DESCRIPTION OF THE PREFERRED EMBODIMENT
21 As previously stated, the invention involves modifying the conventional 22 SAGD process by managing the steam delivery point in the injection well as 23 follows:
24 ~ locating the steam delivery dint during the first stage of the process at the toe end of the horizontal wellbore section; and 1 ~ locating the steam delivery point during the second stage 2 intermediate the heel and toe.
3 In the preferred mode, this is accomplished by landing the outlet 1 of 4 the injection well tubing string 2 at the toe of the well 3 for the duration of the first stage. The tubing string is then withdrawn to re-locate its outlet at the 6 heel or at a point intermediate the toe and heel for the duration of the second 7 stage. Those of ordinary skill in the art will know how to accomplish the 8 foregoing without further instruction.
9 As an alternative, one could land the tubing string in the horizontal section of the well, but spaced from the toe, in the first stage and use a 11 second string of coil tubing to deliver the steam to the toe of the well.
9 Steam-assisted gravity drainage ("SAGD") is the label used to identify a thermal, two-stage process used in recent years to recover very viscous oil 11 from a subterranean formation or reservoir at shallow depth.
12 The SAGD process was originally developed to recover oil from the 13 McMurray oil sand, in northern Alberta, at depths of about 100 meters or 14 greater.
The oil in this formation is so viscous that it is immobile. It must be 16 heated to reduce its viscosity and increase its mobility, before there is any 17 chance of producing it.
18 The process, as heretofore practised, has involved the following:
19 ~ A pair of wells are drilled down from ground surface and have a horizontal wellbore section completed in the base portion of the 21 reservoir. The horizontal sections of the two wells are parallel and 22 co-extensive. The horizontal section of one well is usually 23 positioned directly above the other, in closely spaced relationship.
24 The upper well is referred to as the steam injection well and the lower well as the production well;
1 ~ Each well has a "heel" (where the downwardly extending wellbore 2 bends to horizontal) and a "toe" (the furthest extremity of the 3 horizontal section);
4 ~ Each well is typically completed with a scxeened sand exclusion liner extending along the length of the horizontal section of the well;
6 ~ Each well is equipped with a string of tubing extending into the 7 horizontal liner;
8 ~ In a first stage of the process, fluid transmissibility is established 9 across the span of formation separating the wells. In some reservoirs, this interwell span is saturated with immobile oil, so that 11 heated oil and steam condensate cannot drain through the span to 12 reach the production well. To achieve transmissibility, the following 13 procedure has successfully been applied in these reservoirs. The 14 tubing string in each well is landed at the toe of the well. Steam is circulated down the tubing and back through the annulus of the well 16 to create two parallel hot elements, which heat the span between 17 them by thermal conduction. Once the oil in the span is sufficiently 18 heated to be mobile, a differential in circulating pressure maintained 19 between the two wells will cause the oil in the span to be displaced into the production well. Steam and steam condensate replaces the 21 displaced oil in the permeable channels extending through the 22 span. When this is achieved, the span is now in condition to enable 23 liquid drainage therethrough. In other reservoirs containing a lighter 24 and more mobile oil, it is only necessary to inject steam through the upper well, with the lower well open, and displace the oil in the span 1 with steam. Again, the span is now in condition to enable liquid 2 drainage therethrough;
3 ~ At this point, the second stage of the process is initiated. The 4 injection well is converted to steam injection, simultaneously through the well annulus and the tubing string. The production well 6 is converted to liquid production. The wells are now ready to work 7 in tandem or to co-operate to recover oil from the reservoir by the 8 mechanism of steam-assisted gravity drainage. Steam is injected 9 through the injection well. The steam rises and heats up the cold oil directly above the injection well. The heated oil and steam 11 condensate drain downwardly through the interwell span to the 12 production well and are produced therethrough to ground surface.
13 Over time, a large oil-depleted chamber is developed, extending 14 upwardly from the pair of co-operating wells, as much of the oil in the section of reservoir overlying the wells is mobilized and 16 produced.
17 When the SAGD process was being initially demonstrated in the field, 18 the length of the horizontal sections of the wells was only in the order of 19 200 meters. It was anticipated that if the horizontal sections were double that length, then the production rates and recovered oil volumes should also 21 double. However, when co-0perating pairs of wells with double the horizontal 22 section length were put into production, it was found that performance did not 23 meet expectations. In fact the production rate and oil recovered was only 24 about 50°r6 greater. It was clear that there was a problem and it was not self-evident what this problem was.
2 The present invention is based on the discovery that, when the tubing 3 string is landed at the toe of the injection well and steam is injected through 4 the annulus and tubing string simultaneously in the second stage of the SAGD
process, the steam predominantly leaks or enters the formation from the well 6 in the areas of the heel and toe. Otherwise stated, steam injection is 7 concentrated at the heel and toe. As a result, there is a likelihood that steam 8 short-circuiting to the production well in one or both of these areas will take 9 place. In addition, much of the oil along the interval between heel and toe will remain unheated and unproduced.
11 The discovery and recognition of the problem arose from an analysis of 12 data from field pilot wells and from subsequent numerical modelling. These 13 investigations indicated:
14 ~ that, if one compares the annulus pressure profiles of the injection and production wells, along the horizontal intervals;
16 ~ then one finds that at the heel and toe areas of the two wells there 17 was a positive pressure differential (that is, the pressure in the 18 annulus of the injection well was greater than that in the annulus of 19 the production well) but I~tween the heel and toe areas, there was a negative pressure differential (that is, the pressure in the annulus 21 of the injection well was less than that in the annulus of the 22 production well); and 1 ~ this was accompanied by a steam leakage profile which showed 2 that steam injection was higher at heel and toe than in between, 3 and a temperature profile which indicated that the temperature in 4 the interwell span was higher at heel and toe than it was in between.
6 It is our belief that these observed results are largely induced by 7 pressure loss experienced by the steam due to friction as it moves along the 8 horizontal wellbore annulus.
9 If there is relatively high steam leakage into the reservoir at the heel and toe areas of the well, then this of course means that there is relatively 11 little heating of the reservoir along the production interval intermediate the 12 heel and toe.
13 In accordance with the invention, the SAGD process has therefore 14 been modified as follows:
~ during the first stage of the process, steam is delivered through the 16 tubing string in the injection well at the heel or at the toe end of the 17 horizontal well section; but 18 ~ during the second stage, steam is injected through both the 19 annulus and the tubing string in the injection well and the steam delivery point of the tubing string is maintained at a point 21 intermediate the heel and toe of the horizontal wellbore section.
22 In a preferred embodiment, we land the end of the tubing string at the 23 toe end of the injection well when establishing transmissibility and retract the 24 string to land its end intermediate the toe and heel during the SAGD stage.
{E3082663.DOC;1 }5 1 By doing this we have achieved the following:
2 ~ the length of the horizontal annulus (the passageway formed 3 between liner and tubing string) has been shortened. The pressure 4 drop per lineal meter in the liner alone is only a fraction of the pressure drop in the annulus between the tubing string and liner.
6 By shortening the horizontal annular space, we have significantly 7 reduced the pressure drop experienced by steam moving along the 8 horizontal section of the well; and 9 ~ we have ensured that the steam issuing from the tubing string is certain to heat the reservoir as it moves between the delivery point 11 and the toe end of the horizontal section.
14 Figure 1 is a schematic showing a pair of horizontal wells for co-operating to carry out the first stage of a SAGD process, the wells each being 16 equipped with a liner and a tubing string; and 17 Figure 2 is a schematic showing the wells of Figure 1 with the tubing 18 string of the injection well re-positioned so that the annulus is shortened.
DESCRIPTION OF THE PREFERRED EMBODIMENT
21 As previously stated, the invention involves modifying the conventional 22 SAGD process by managing the steam delivery point in the injection well as 23 follows:
24 ~ locating the steam delivery dint during the first stage of the process at the toe end of the horizontal wellbore section; and 1 ~ locating the steam delivery point during the second stage 2 intermediate the heel and toe.
3 In the preferred mode, this is accomplished by landing the outlet 1 of 4 the injection well tubing string 2 at the toe of the well 3 for the duration of the first stage. The tubing string is then withdrawn to re-locate its outlet at the 6 heel or at a point intermediate the toe and heel for the duration of the second 7 stage. Those of ordinary skill in the art will know how to accomplish the 8 foregoing without further instruction.
9 As an alternative, one could land the tubing string in the horizontal section of the well, but spaced from the toe, in the first stage and use a 11 second string of coil tubing to deliver the steam to the toe of the well.
Claims (2)
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:
1. In the process for recovering heavy oil from a subterranean reservoir using a co-operating pair of steam injection and oil production wells having parallel, vertically spaced apart, horizontal sections extending through the reservoir adjacent its base, said process involving sequential stages of first establishing interwell fluid transmissibility through the span of reservoir extending between the horizontal well sections and then practising steam-assisted gravity drainage, said wells each having a string of tubing in place within a sand exclusion liner, each string of tubing and its liner forming an annulus between them, each well having a heel and toe, the improvement comprising:
managing the location of the delivery point of steam through the injection well tubing string as follows, during the course of the first stage of establishing interwell fluid transmissibility, locating the steam delivery point of the tubing string adjacent the toe of the injection well, and during the course of the second stage of practising steam-assisted gravity drainage, injecting steam at the injection well through both the annulus and the tubing string and maintaining the steam delivery point of the tubing string at the heel or at a point intermediate the toe and heel of the injection well for the injection of steam therethrough.
managing the location of the delivery point of steam through the injection well tubing string as follows, during the course of the first stage of establishing interwell fluid transmissibility, locating the steam delivery point of the tubing string adjacent the toe of the injection well, and during the course of the second stage of practising steam-assisted gravity drainage, injecting steam at the injection well through both the annulus and the tubing string and maintaining the steam delivery point of the tubing string at the heel or at a point intermediate the toe and heel of the injection well for the injection of steam therethrough.
2. The improvement as set forth in claim 1 wherein:
the tubing string is landed adjacent the toe of the injection well during the first stage and steam is circulated from the toe of the well back through the annulus, and the tubing string is landed intermediate the toe and heel of the injection well during the second stage.
the tubing string is landed adjacent the toe of the injection well during the first stage and steam is circulated from the toe of the well back through the annulus, and the tubing string is landed intermediate the toe and heel of the injection well during the second stage.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2313837 CA2313837C (en) | 2000-07-13 | 2000-07-13 | Positioning of the tubing string in a steam injection well |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2313837 CA2313837C (en) | 2000-07-13 | 2000-07-13 | Positioning of the tubing string in a steam injection well |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2313837A1 CA2313837A1 (en) | 2002-01-13 |
| CA2313837C true CA2313837C (en) | 2004-09-14 |
Family
ID=4166701
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2313837 Expired - Lifetime CA2313837C (en) | 2000-07-13 | 2000-07-13 | Positioning of the tubing string in a steam injection well |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2313837C (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9976403B2 (en) | 2012-06-28 | 2018-05-22 | Carbon Energy Limited | Method for shortening an injection pipe for underground coal gasification |
Families Citing this family (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CA2762451C (en) | 2011-12-16 | 2019-02-26 | Imperial Oil Resources Limited | Method and system for lifting fluids from a reservoir |
| CA2780670C (en) | 2012-06-22 | 2017-10-31 | Imperial Oil Resources Limited | Improving recovery from a subsurface hydrocarbon reservoir |
| US9435184B2 (en) | 2012-06-28 | 2016-09-06 | Carbon Energy Limited | Sacrificial liner linkages for auto-shortening an injection pipe for underground coal gasification |
| CA3022404C (en) * | 2015-04-28 | 2022-01-25 | Martin Parry Technology Pty Ltd | Moving injection gravity drainage for heavy oil recovery |
-
2000
- 2000-07-13 CA CA 2313837 patent/CA2313837C/en not_active Expired - Lifetime
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9976403B2 (en) | 2012-06-28 | 2018-05-22 | Carbon Energy Limited | Method for shortening an injection pipe for underground coal gasification |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2313837A1 (en) | 2002-01-13 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKEX | Expiry |
Effective date: 20200713 |