Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02461237 2004-03-18
1 "UTILIZING HEAT AT A STEAM ASSISTED GRAVITY
2 DRAINAGE OIL RECOVERY OPERATION"
3
4 FIELD OF THE INVENTION
The present invention is concerned with an improvement of the oil
6 recovery process known as steam assisted gravity drainage ('SAGD'). More
7 particularly it is concerned with a process and apparatus for utilizing heat
in
8 wellhead separator produced vapors.
9
BACKGROUND OF THE INVENTION
11 SAGD is a known thermal oil recovery process. It is principally used in
12 connection with subterranean reservoirs containing heavy oil that is so
13 viscous that it needs to be heated sufficiently to become mobile and
14 producible.
The process will now be described with regard to specific temperature
16 and pressure values which were encountered at applicant's MacKay River
17 SAGD operation in Alberta. These values are only exemplary, as they varied
18 operation over time and may be quite different at another SAGD operation
19 conducted at another reservoir.
In accordance with SAGD:
21 ~ A pair of wells are drilled down from ground surface and are turned
22 to extend horizontally in the reservoir, close to its base. The
23 horizontal legs of the wells are generally co-extensive and parallel,
24 with one spaced closely above the other. The upper well is
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1 completed for steam injection; the lower well is completed for fluid
2 production. Usually a plurality of such pairs of wells are provided,
3 extending from a surface location referred to as a 'pad'. These
4 pairs of wells can be said to be cooperatively arranged for the
practice of SAGD;
6 ~ A central 'plant' is provided. The plant includes boiler equipment for
7 generating high pressure/high temperature steam. The plant
8 usually functions to supply steam to a plurality of pads. The steam
9 is conveyed through a pipeline from the plant to a manifold at each
pad. The manifold is connected to selectively supply plant steam to
11 one or both wells of each pair;
12 ~ As mentioned, the steam supplied is at high temperature/pressure.
13 For example, it might be at 576°K and 9,000 kPa (1305 psi). At this
14 level of pressure the plant steam is dense and suitable for
economical transmission through pipelines out to the pads;
16 ~ Prior to injection into the wells, the high pressure steam is throttled
17 by passing it through pressure let-down valves to reduce its
18 pressure to injection level. For example, the injection pressure
19 might be in the order of 2000 kPa (290 psi). This is done to avoid
injecting into the usually shallow reservoir at a pressure that would
21 be likely to induce formation fracturing;
22 ~ In the first step of the SAGD process, steam is circulated through
23 both wells of each pair to heat the span of formation between the
24 wells by conductance. Once the oil in the span is mobile, it is
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displaced into the lower production well by pressure differential, to
2 thereby leave the span in condition for fluid transmission;
3 ~ At this point, the upper injection well is converted to steam injection.
4 The lower production well is converted to fluid production. As
steam is injected through the injection well, it rises and heats the
6 cold oil immediately thereabove. The heated oil drains down
7 through the span and enters the production well. Over time, an
8 upwardly growing, permeable 'steam chamber' (from which the oil
9 has drained) is developed. The produced heated oil is
accompanied by water, mainly derived from condensed steam. It
11 also is accompanied by vapors, usually some steam, hydrogen
12 sulfide (H2S) and natural gas. Thus a 'fluid', comprising liquids and
13 vapors, is produced through the production well. This fluid is under
14 pressure and rises through the vertical leg of the production well
and is produced at ground surface. Otherwise stated, the fluid is
16 self-lifting and flows to surface;
17 ~ As the fluid rises through the production well, some contained water
18 flashes to form steam as the pressure in the production tubing
19 diminishes due to hydrostatic head and friction losses. So when the
fluid arrives at ground surface, it contains a significant proportion of
21 steam; and
22 ~ The produced fluid is processed at the pad in a wellhead separator
23 to separate liquids and vapors. Separate liquid and vapor streams
24 issue from the separator.
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1 To this point applicant has described what may be referred to as a
2 'basic' SAGD operation. However, it will be known by those skilled in the
art
3 that the basic process can be enhanced, for example by adding a non-
4 condensible gas (such as methane) or a solvent to the steam being injected.
It is therefore to be understood that the expressions 'steam assisted gravity
6 drainage', 'steam assisted gravity drainage operation', and 'SAGD' are
7 intended to encompass the basic process and such enhanced processes.
8 The present invention is primarily concerned with the 'vapors' produced
9 from the wellhead separator and with several problems and considerations
related thereto. More particularly:
11 ~ The vapors contain substantial heat which needs to be efficiently
12 utilized. Otherwise, expensive natural gas will need to be burned to
13 make up for the lost heat values;
14 ~ One solution which was used at applicant's operation for this
purpose has involved feeding the vapor stream through a return
16 pipeline back to the central plant for heat recovery by heat
17 exchange. However the wellhead separator needed to be operated
18 at low pressure to avoid holding back pressure on the production
19 wells. In other words, in order to maintain fluid production at useful
rates, it was desirable to keep the wellhead separator pressure low.
21 However the separator pressure had to be high enough to drive the
22 vapors through the return pipeline to the plant. There was, of
23 course, a pressure loss due to friction in the return pipeline. Thus
24 the vapor stream arrived at the plant in a state of low pressure and
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1 temperature, which was not conducive to effective heat exchange.
2 For example, the wellhead separator pressure might have been at
3 about 900 kPa (130 psi). At this separator pressure, only about 30
4 - 40% of the contained heat was recovered at the plant by heat
5 exchange;
6 ~ Another possibility would be to add a compressor to the vapor
7 return pipeline to increase the vapor pressure and temperature prior
8 to heat exchange. However this is expensive to do and the vapors
9 usually comprise H2S and water particles containing chlorides,
which are destructive of the compressor's working components;
11 ~ Still another solution would be to re-inject the vapors into the
12 reservoir at the pad. However, the fresh plant steam is at high
13 pressure and the low pressure separator vapors can't be fed into
14 the high pressure steam line.
Another problem associated with these issues is that the SAGD
16 injection process is temporarily terminated from time to time due to
upsets.
17 As a result, draining fluid builds up as a column over the production wells
and
18 the fluid cools. Under these conditions it is difficult to initiate
production and
19 maintain it at elevated rates to bring the fluid level down to the
production
wells.
21 From the foregoing it will be understood that there has long existed a
22 need for a better strategy in SAGD operations to deal with the separator
23 vapors to efficiently utilize their heat content and to improve on the
removal
24 rate of fluid from the reservoir.
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1 SUMMARY OF THE INVENTION
2 In accordance with the invention, in an on-going SAGD operation high
3 pressure steam coming from the central plant is used at the pad to draw in
4 and compress relatively low pressure wellhead separator vapors to produce a
composite stream at intermediate pressure. The composite stream is
6 subsequently throttled to reduce its pressure to a pre-determined suitable
7 injection pressure and is then injected through the injection wells) into
the
8 reservoir.
9 A thermal compressor, such as an eductor, is connected by a suction
line with the wellhead separator vapor outlet and by a connection with the
11 plant steam pipeline. The compressor is used to draw in the low pressure
12 vapors produced by the wellhead separator, to combine them with the high
13 pressure plant steam for compression thereby. In such a device, a high
14 velocity jet of motive plant steam is discharged across a suction chamber
that
is connected to the suction line conveying the separator vapors. The low
16 pressure vapors are drawn or sucked in by a low pressure condition created
17 in the chamber by the jet and become entrained with the plant steam. The
18 resulting mixture is conducted into a venturi-type shaped diffuser, which
19 converts the kinetic energy into pressure energy. This is commonly known as
the pressure recovery process. The resulting mixture has an intermediate
21 pressure between the separator pressure and the plant steam pressure.
22 As previously stated, the thermal compressor and its actions are
23 incorporated into a SAGD 'operation' (i.e. facility and on-going
operational
24 steps) involving cooperatively arranged pairs of injection and production
wells
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1 and a wellhead separator, all at a pad, a remote plant producing high
2 pressure steam for injection and a pipeline conveying the plant steam to the
3 pad.
4 In one aspect of the invention, there is therefore provided a process for
use in thermally recovering oil-containing fluid produced from a subterranean
6 heavy oil reservoir, comprising: providing a steam assisted gravity drainage
7 operation having a plurality of cooperatively arranged pairs of injection
and
8 production wells located at a pad, said wells extending down from ground
9 surface and penetrating generally horizontally into the reservoir, a plant
generating high pressure steam and located remote from the pad, a pipeline,
11 extending between the plant and the pad, conveying high pressure plant
12 steam to the injection wells, and a wellhead separator, located at the pad,
13 processing fluid, comprising liquids and vapors, produced from the
reservoir
14 through the production wells, to separate the liquids and vapors and
produce
separated vapors at low pressure; combining the separated vapors with the
16 plant steam and compressing the vapors with the plant steam to produce an
17 injection mixture at intermediate pressure; throttling the injection
mixture to
18 reduce its pressure to a pre-determined value appropriate for injection
into the
19 reservoir; injecting the throttled injection mixture into the reservoir
through the
injection wells and simultaneously producing fluid from the reservoir through
21 the production wells in the course of practicing steam assisted gravity
22 drainage in the reservoir; and feeding the fluid produced by the production
23 wells to the separator for processing.
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1 In another aspect of the invention there is provided a facility for use in
2 recovering fluid produced from a subterranean heavy oil reservoir,
comprising:
3 a plurality of cooperatively arranged pairs of injection and production
wells
4 located at a pad, said wells extending down from ground surface and
S penetrating generally horizontally into the reservoir; a plant, for
generating
6 high pressure steam, located remote from the pad; a pipeline, extending
7 between the plant and the pad, for conveying plant steam to the injection
8 wells; a wellhead separator, located at the pad and connected with the
9 production wells, for processing fluid produced from the reservoir to
separate
contained vapors and liquids and to separately produce separated vapors; a
11 thermal compressor, connected to the separator and pipeline, for combining
12 the vapors with the plant steam and compressing the vapors with the plant
13 steam to produce an injection mixture; means, connected with the thermal
14 compressor, for receiving the injection mixture and throttling it to reduce
its
pressure to a value appropriate for injection into the reservoir; and means,
16 connected with the throttling means, for conveying the throttled mixture to
the
17 injection wells for injection into the reservoir.
18
19 DESCRIPTION OF THE DRAWING
Figure 1 is a schematic representation of a facility, partly in plan view
21 and partly in side view, in accordance with the invention; and
22 Figure 2 is a plan sectional view showing the eductor.
23
24 DESCRIPT10N OF THE PREFERRED EMBODIMENT
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1 Having reference to Figure 1, a facility 1 for practicing SAGD is shown.
2 The facility 1 comprises:
3 ~ a pair 2 of wells 3,4 extending downwardly from a pad 5
4 located at ground surface 6. The wells 3,4 penetrate
horizontally co-extensively and in parallel in vertically spaced
6 relationship into a subterranean reservoir 7. The upper well
7 3 is completed and equipped in conventional manner for
8 steam injection. The lower well 4 is completed and equipped
9 in conventional manner for fluid production. In summary, the
pair 2 of injection and production wells 3,4 are cooperatively
11 arranged for SAGD procedure;
12 ~ a conventional SAGD plant 10 located remote from the pad 5
13 and having a boiler 11 for generating high pressure steam
14 12;
~ a pipeline 13 for conveying plant steam 12 from the plant 10
16 to a manifold 14 located at the pad 5;
17 ~ a conventional wellhead separator 15, located at the pad 5
18 and connected with the production well 4, for receiving a
19 stream 16 of produced fluid and separating it into liquid and
vapor streams 17, 18;
21 ~ an eductor 20 located at the pad 5;
22 ~ a suction line 21, connected between the separator 15 and
23 eductor 20, for conveying the vapor stream 18 into the
24 suction chamber 22 of the eductor 20;
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1 ~ a line 23 connecting the manifold 14 with the eductor 20, for
2 delivering plant steam 12 into the suction chamber 22
3 through the nozzle 24 for mixing with the vapor 18 in the
4 diffuser section 25 of the eductor 20 to produce a gaseous
5 mixture 26;
6 ~ a throttling assembly 27, having pressure let-down valves 28,
7 connecting the outlet of the diffuser section 25 with the
8 injection well 3, for reducing the pressure of the gaseous
9 mixture 26 and introducing it into the injection well 3.
10 In operation, high pressure plant steam 12 is generated by the plant 10
11 and conveyed through the pipeline 13 and manifold 14 to the eductor 20,
into
12 which it is discharged through the nozzle 24 as a jet 30. At the same time,
13 produced fluid 16 is discharged from the production well 4 into the
wellhead
14 separator 15, which is operated at low pressure. The fluid 16 is separated
in
the separator 15 to produce liquid 17 and vapor 18. The low pressure vapor
16 18 is conveyed through the suction line 21 and is drawn into the eductor
17 chamber 22. The plant steam 12 and vapor 18 combine and the steam
18 compresses the vapor. They mix as they move through the eductor chamber
19 22 and diffuser section bore 29 and produce gaseous mixture 26 at
intermediate pressure. The mixture 26 is passed through the throttling
21 assembly 27 to reduce its pressure to injection pressure. The mixture 26 is
22 injected into the reservoir 7 through the injection well 3. The injected
mixture
23 26 rises and heats cold oil at the surface 30 of the steam chamber 31.
24 Heated oil drains, together with steam condensate, through the steam
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chamber 31 in the course of steam assisted gravity drainage, and is produced
2 as fluid 16 through the production well 4. This fluid 16 is introduced into
the
3 separator 15.
4
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