Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02313837 2000-07-13
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.
7
8 BACKGROUND OF THE INVENTION
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;
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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
2
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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
100 -
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.
3
CA 02313837 2000-07-13
1 SUMMARY OF THE INVENTION
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
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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
CA 02313837 2000-07-13
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.
12
13 DESCRIPTION OF THE DRAWINGS
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.
19
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
6
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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.
7
