CA2461237C - Utilizing heat at a steam assisted gravity drainage oil recovery operation - Google Patents

Abstract

In an on-going steam assisted gravity drainage process for recovering oil from a subterranean reservoir, vapors from a wellhead separator are compressed with high pressure plant steam using an eductor, to produce a mixture that is injected into the reservoir. As a result, heat contained by the vapors is efficiently utilized.

Description

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.

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 tE4145997.DOC;1 t 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 jE4145997.DOC;1 ~

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.
E4145997.DOC;1 }

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 E4145997.DOC;1 f 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.
( E4145997. DOC;1 f 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 t E4145997. DOC;1 f 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.
j E4145997. DOC; l f 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.

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.

( E4145997.DOC;1 t 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;
E4145997.DOC;1 t 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 { FA 145997. DOC;1 {

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.

j E4145997. DOC; l f

Claims (2)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:

1. A process for use in thermally recovering oil-containing fluid produced from a subterranean heavy oil reservoir, comprising:
providing a steam assisted gravity drainage operation having a plurality of cooperatively arranged pairs of injection and production wells located at a pad, said wells extending down from ground surface and penetrating generally horizontally into the reservoir, a plant generating high pressure steam, located remote from the pad, a pipeline, extending between the plant and the pad, conveying high pressure plant steam to the injection wells, and a wellhead separator, located at the pad, processing fluid produced from the reservoir through the production wells, said separator separating produced liquids and vapors and separately producing separated vapors at low pressure;
combining the separated vapors with the plant steam and compressing the vapors with the plant steam to produce an injection mixture at intermediate pressure;
throttling the injection mixture to reduce its pressure to a pre-determined value appropriate for injection into the reservoir;
injecting the throttled injection mixture into the reservoir through the injection wells and simultaneously producing fluid from the reservoir through the production wells in the course of practicing steam assisted gravity drainage in the reservoir; and feeding the fluid produced by the production wells to the separator for processing.

2. A facility for thermally recovering oil-containing fluid from a subterranean heavy oil reservoir using steam assisted gravity drainage, comprising:
a plurality of cooperatively arranged pairs of injection and production wells located at a pad, said wells extending down from ground surface and penetrating generally horizontally into the reservoir;
a plant, for generating high pressure steam, located remote from the pad;
a pipeline, extending between the plant and the pad, for conveying plant steam to the injection wells;
a wellhead separator, located at the pad and connected with the production wells, for processing fluid produced from the reservoir to separate contained vapors and liquids and to separately produce separated vapors;
a thermal compressor, connected to the separator and pipeline, for combining the vapors with the plant steam and compressing the vapors with the plant steam to produce an injection mixture;
means, connected with the thermal compressor, for receiving the injection mixture and throttling it to reduce its pressure to a value appropriate for injection into the reservoir; and means, connected with the throttling means, for conveying the throttled mixture to the injection wells for injection into the reservoir.