CA2769044C - Fluid injection device - Google Patents

Abstract

The present invention is directed to a fluid injection device comprising an inner tubular having a first end, a second end, an inner bore and a plurality of inlet ports passing through the inner tubular proximate a first end of the inner tubular; and an outer sleeve having a first end, a second end and a plurality of outlet ports located proximate the second end of the outer sleeve and passing through the outer sleeve, the outer sleeve sized to fit over the inner tubular so that the first end covers the ports in the inner tubular and forms an annulus between the inner tubular and the outer sleeve; whereby fluid injected into the inner bore of the inner tubular enters the annular space through the inlet ports and is discharged from the device through the outlet ports. In a further aspect, the present invention is directed to a system for distributing steam in a wellbore using the fluid injection device.

Description

FLUID INJECTION DEVICE
The present invention relates to fluid injection devices and more particularly to a fluid injection device used to inject steam or another fluid into an earthen formation as part of a fluid assisted operation to decrease the viscosity of the bituminous ore, oil sands, oil shale, tar sands, or heavy oil in the earthen formation causing it to drain into a production well.
BACKGROUND OF THE INVENTION
To facilitate the production of bituminous ore, oil sands, oil shale, tar sands, or heavy oil from in situ operations, including oil sands deposits, shale deposits and carbonate deposits, the deposits are often heated to separate the hydrocarbons from the other geologic materials and to reduce the viscosity of the hydrocarbons (by maintaining the hydrocarbons at temperatures at which they will flow. Several methods are known for recovering hydrocarbons from such formations by increasing the mobility of the oil, including cyclic steam stimulation (CSS), a steam flood (SF) process and a steam assisted gravity drainage (SAGD) process. Each of these processes use steam to heat and mobilize the oil and mobilized oil is recovered using a production well.
For example, in SAGD, two parallel horizontal wells are drilled vertically adjacent to each other in a formation. The upper well is an injection well and the lower well is a production well.
Steam is first introduced into both wells to heat heavy oil adjacent to the wells. Heavy oil drains into the production well creating a porous formation through which steam permeates outwardly to heat the formation. When heated oil can flow from the injection well to the production well, steam injection into the production well is stopped. Steam is injected into the injection well to heat a larger region surrounding the wells to continue extraction of heavy oil. In addition to steam, other heated fluids can be used, such as a chemical/steam mixture that reduces the viscosity by a chemical interaction as well as heating it.
The pressurized vapour is typically injected into the earthen formation by running an injection tubing string inside a slotted liner. The vapour then passes out of the end of injection string and through the liner into the earthen formation. The liner does not significantly impede the flow of the vapour from within the slotted liner outside to the earthen formation.
This is accomplished in conventional techniques by providing multiple injection locations and alternative means. In a horizontal well which is used only for steam injection at subfracture reservoir pressures, steam distribution can be achieved by running injection strings into the wellbore to provide steam injection at specific points. This method is limited by the size of the casing and size of the injection strings. Other less successful methods include varying the number and size of holes in the liner, such that at the desired steam injection rates, critical flow is achieved through the holes and equitable steam distribution at each hole location is intended. Alternatively, the target steam injection rates can be constrained such that only a minimal pressure drop occurs along the liner. Both of these design criteria put significant constraints on the steam injection operation.
Designing for critical flows means that the peak injection rates are capped.
One of problems associated with conventional techniques is that when injection occurs at one or more points inside the liner, vapour delivery to the deposits/earthen formation is concentrated at those points and diminishes as the distance is increased away from them. This can result in non-uniform, uneven vapour distribution into the earthen formation along the length of the injection well.
This uneven vapour distribution can cause uneven and hence reduced production from the well.
Furthermore, conventional methods for SAGD are unable to provide targeted steam distribution in a formation.
The fluid injection device of the present invention has the potential to address some of the problems with known thermal stimulation processes. For example, the fluid injection device improves the distribution of the fluid being injected by increasing the flow rate of the fluid out of the fluid injection devices further from the injection points. Furthermore, the fluid injection devices of the present invention provides approximate linear increase in pressure drop in relation to increase in flowrate of the fluid being injected.

2 SUMMARY OF THE INVENTION
In accordance with one aspect of the present invention, there is provided a fluid injection device comprising: an inner tubular having a first end, a second end, an inner bore and a plurality of inlet ports passing through the inner tubular proximate a first end of the inner tubular; and an outer sleeve having a first end, a second end and a plurality of outlet ports located proximate the second end of the outer sleeve and passing through the outer sleeve, the outer sleeve sized to fit over the inner tubular so that the first end covers the ports in the inner tubular and forms an annulus between the inner tubular and the outer sleeve; whereby fluid injected into the inner bore of the inner tubular enters the annular space through the inlet ports and is discharged from the device through the outlet ports.
In a further aspect of the present invention, there is provided a fluid injection device further comprising one or more raised ring segments positioned in between the first and second ends of the inner tubular, wherein the raised ring segments encircle the inner tubular and extend radially outward from the surface of the inner tubular into the annular space.
In a further aspect of the present invention, there is provided a system for distributing steam in a wellbore in a subterranean formation, the system comprising: a plurality of fluid injection devices according to the present invention; one or more injection lines passing through the inner bores of the inner tubular of the fluid injection devices; wherein fluid is injected into the plurality of fluid injection devices through the injection lines. The plurality of fluid injection devices of the present invention can be incorporated directly into the casing inserted into a formation. Alternatively, they can be run as a string of fluid injection devices inside a slotted casing.
It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

3 BRIEF DESCRIPTION OF THE DRAWINGS
Referring to the drawings wherein like reference numerals indicate similar parts throughout the several views, several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:
Fig. 1 is a schematic illustration of a string of fluid injection devices installed in a horizontal well bore for injection of fluid into a soil formation adjacent the well bore;
Fig. 2 is a perspective view of a fluid injection device;
Fig. 3 is a top view of an inner tubular of the fluid injection device shown in Fig. 2;
Fig. 4 is a side sectional view of the inner tubular shown in Fig. 3 along line AN;
Fig. 5 is atop view of an outer sleeve of the fluid injection device shown in Fig. 2;
Fig. 6 is a side section view of the outer sleeve of the fluid injection device shown in Fig. 5 along line BB';
Fig. 7 is a schematic illustration of the fluid injection device of Fig. 2;
Fig. 8 is a schematic sectional illustration of the fluid injection device of Fig. 2;
and Fig. 9 is a graph showing test results of the fluid injection device in an example.
DESCRIPTION OF THE VARIOUS EMBODIMENTS
The detailed description set forth below in connection with the appended drawings is intended as a description of various embodiments of the present invention and is not intended to represent the only embodiments contemplated by the inventor. The detailed description includes specific details and specifications regarding the illustrated embodiments for the purpose of providing a comprehensive understanding of the present invention. It will be apparent to those skilled in the art that the present invention may be practiced without these specific details.
Fig. 1 illustrates a string of fluid injection devices 100 installed in a horizontal wellbore 20. A number of injection lines 10A, 10B are installed passing through inner bores 118 of the fluid injection devices 100. Fig 1 illustrates a first injection line 10A positioned so that fluid, such as steam, exits the first injection line 10A near a heel area 12 at a first injection point 15A and a second injection line

4 10B positioned inside the inner bores 118 of the fluid injection devices 100 so that a fluid, such as steam, exits the second injection line 10B at a second injection point 15B
near a toe area 14.
A soil formation 30 containing bitumen is present adjacent to the wellbore 20.
Fluid, such a steam, some other vapour, etc., can be injected into the well bore 20 and the earthen formation 30 using the fluid injection lines 10A, 10B and the string of fluid injection devices 100 in order to heat the earthen formation, decreasing the viscosity of the bitumen and causing it to flow into a production well (not shown) where it can be collected.
Although Fig. 1 illustrates a first injection line 10A and a second injection line 10B, a person skilled in the art will appreciate that any suitable number of injection lines could be provided and their positioning within the string of fluid injection devices 100 could vary depending on the particular circumstances. In one aspect, only a single injection line could be used; supplying steam or some other fluid to a single location in the string of fluid injection devices 100, such as the heel area 12 or the toe area 14.
Fig. 2 illustrates a fluid injection device 100 in one aspect. The fluid injection device 100 can be used as part of the string of fluid injection devices 100, shown in Fig. 1, to try and provide a more ideal and targeted distribution of fluid along the well bore 20 and to increase the flowrate of the fluid discharging further away from the injection points 15A, 15B at the ends of the first and second injection lines 10A, 10B. The fluid injection device 100 can include an inner tubular 110 and an outer sleeve 150.
Figs. 3 and 4 illustrate the inner tubular 110 of the fluid injection device 100. The inner tubular 110 has a first end 112, a second end 114, an outside surface 116 and an inner bore 118.
Located proximate the first end 112 are a plurality of ports 120 (inlet ports) passing through the inner tubular 110 and into the inner bore 118. The inlet ports 120 can be positioned spacedly apart and encircling the inner tubular 110.
A number of raised ridges 130 can be provided on the outside surface of the inner tubular 110. These ridges 130 can be spaced longitudinally apart from each other along the outer surface 116 of the inner tubular 110 between the inlet ports and the second end 114. Each ridge 130 can encircle the inner tubular 110 and protrude outwards from the outside surface 116 (i.e.
forming a raised ring protrusion or vertical bar wrapping around the circumference of the inner tubular 110). The ridges 130 form support ring structures that also function to centralize the inner tubular 110 and outer sleeve 150 (discussed below). Each of the ridges 130 can have one or more circumferentially spaced gaps 135 passing through the ridge 130. In one aspect, two or more raised ridges 130 can be provided adjacent to one another with the gaps 135 in a first ridge 130 positioned so that they do not align with the gaps 135 in the adjacent ridge 130.
A raised seat 138 can also be provided so that the outer sleeve 150 can be seated against the raised seat 138, holding the outer sleeve 150 in place.
The outside surface 116 of the inner tubular 110 can also be provided with a number of roughened sections 140 between the inlet ports and the second end 114 of the inner tubular 110. In the roughened sections 140, the outside surface 116 of the inner tubular 110 can be made rough, such as by grooving, indenting, machining, etc. of the surface to increase the frictional effect of the roughened sections 140 on a flow of fluid passing over the roughened section 140.
In one aspect, the roughened sections 140 can be provided between the ridges 130.
Figs, 5 and 6 illustrate the outer sleeve 150 of the fluid injection device 110. The outer sleeve 150 can have a first end 152 and a second end 154. The outer sleeve 150 can be substantially non-perforated along the majority of its length, with a series of ports 160 (outlet ports) provided proximate the second end 154 of the outer sleeve 150 (i.e. outlet ports). These outlet ports 160 are shown as elongate slots in Fig. 2, however, they can take any suitable shape such as being circular as shown in Figs. 5 and 6. Additionally, the outlet ports 160 can be provided in the outer sleeve 150 so that the outlet ports 160 encircle the outer sleeve 150.
Although not shown in Figs. 5 and 6, the inner surface of the outer sleeve 150 can also be provided with one or more roughened sections (similar to roughened sections 140 of the outside surface 116 of the inner tubular 110) to increase the frictional effects of the inner surface of the outer sleeve 150 when a flow of fluid is passing over the inner surface.
Fig. 7 illustrates a schematic illustration of the fluid injection device 100.
With the outer sleeve 150 provided in place over the inner tubular 110. The outer sleeve 150 is sized so that its inner diameter is larger than the outer diameter of the inner tubular 110, allowing the outer sleeve 150 to be placed over the inner tubular 110. When the outer sleeve 150 is placed over the inner tubular 110 and slid relative to the inner tubular 110 until the first end 152 of the outer sleeve 150 abuts the raised seat 138, an annulus 180 can be formed between the outside surface 116 of the inner tubular 110 and the outer sleeve 150. The outer sleeve 150 can also be sized so that the inner diameter of the outer sleeve 150 is just larger than the ridges 130 on the outer surface 115 of the inner tubular 110 causing the ridges 130 to contact or nearly contact an inner surface of the outer sleeve 150 when the outer sleeve 150 is in position over the inner tubular 110.
The outer sleeve 150 can be provided over the inner tubular 110 so that the unperforated first end 152 of the outer sleeve 150 is positioned over top of the inlet ports proximate the first end 112 of the inner tubular 110. The outlet ports 160 in the second end 154 of the outer sleeve 150 will be positioned closer to the second end 114 of the inner tubular 110. In this manner, the annulus 180 will define a flow path. Fluid that exist the inlet ports 120 in the inner tubular 110 will pass through this flow path defined by the annulus 180, before the fluid can be discharged from the fluid injection device 100 through the outlet ports 160 in the outer sleeve 150 and injected into the earthen formation.
By making the fluid pass over the roughened sections 140, before it reaches the outlet ports 160 in the outer sleeve 150 and can be discharged out of the fluid injection device 100, the fluid injection device 100 can reduce the outflow of fluid nearer to the injection points, by increasing the backpressure on the fluid that is passing through the annuluses 180 of the fluid injection devices 100 before exiting through the outlet ports 160. This can improve the distribution of the fluid being injected, by increasing the flow rate of the fluid out of the fluid injection devices 100 further from the injection points.
Fig. 8 illustrates the fluid injection device wherein two ridges 130A, 130B
are positioned adjacent to one another with the gaps 135 in the adjacent ridges 130A, 130B
mis-aligned relative to one another. Fluid passing through the annulus 180 towards the outlet ports 160 in the outer sleeve 150 and that has passed through one of the gaps 135 in the first ridge 130A
must move circumferentially through the annulus 180 before it can pass through a gap 135 in the adjacent ridge 130B.
Referring again to Fig. 1, in operation when the fluid injection device 100 is provided in a fluid injection line 10, fluid can be introduced into the earthen formation 30 around the well bore 20 by injecting fluid down the fluid injection lines 10A, 10B where it will be discharged into the inner bores 118 of the string of fluid injection devices 100. The fluid injection devices 100 will then control the outflow of the fluid through the steam injection devices 100 by controlling the pressure drop within the annulus 180 of each fluid injection device 100, the pressure drop of each fluid injection device 100 dependent upon its location along the well bore 20. This can result in the fluid being more evenly distributed along the length of the well bore 20. The number of fluid injection devices used in the string will depend on the well bore and the particular formation being stimulated.
The raised ridges 130 and gaps 135 (i.e. support ring structures), particularly when the gaps 135 are misaligned, as illustrated in Figs. 3 and 8, force the steam to flow in a tortuous path around each ridge. This prevents uneven flow and short circuiting through the fluid injection device.
It is well known that that pressure drops in piping systems normally increases in a non-linear (exponential) manner with an increase in flowrate. The inventors have found that the fluid injection devices of the present invention provide pressure drops that increase in an approximate linear manner with the increase in flowrate. Without being bound by any particularly theory, it is believed that such linear pressure result is achieved by reason of the raised ridges 130 and gaps 135 (i.e. the support ring structures).
The fluid injection device of the present invention provides flow velocities through the tool that are low enough to prevent erosion while still controlling outflow.
A person skilled in the art would understand that wellbore modelling can be utilized to configure the fluid injection devices with a precise combination of geometries specific to the formation and the desired use to provide optimal pressure drop versus flow characteristics. The annular flow path of the injection device creates specific pressure-flow characteristics. The fluid injection device can be used in a variety of applications, for example, CSS, SF and SAGD processes.
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article "a" or "an" is not intended to mean "one and only one"
unless specifically so stated, but rather "one or more". All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims.

Examples The fluid injection device of the present invention was tested under simulated field conditions for the pressures and rates used. Three different fluid injection devices were tested; each had different design elements, which resulted in different pressure drop behaviour. The test results indicated that the fluid injection device would generally provide controlled distribution of steam in a SAGD injection well; including pressure drops that were in the range that would be useful at flowrates that are typical for a SAGD installation. For example, across the three fluid injection devices tested, at a nominal design rate of approximately 17 m3/day cold water equivalent (CWE) of steam, the pressure drops varied from about 35 kPa to 5 kPa.
Table 1 (below) lists some of the specifications for each of the three devices texted. Of the fluid injection devices tested, Example 1, Example 2, and Example 3 ¨ each was constructed to be compatible with 8.625" (219.8 mm) casing. A person skilled in the art would understand that the fluid injection device could be manufactured to be compatible with any desired casing size.
Table 1 ¨ Inlet and Outlet Ports Example 1 Example 2 Example 3 Number of Inlet Ports -14 16 24 Number of Outlet Ports 36 36 36 In the Examples, the roughened sections 140 were made by machining to give a "wavy"
construction on the outside surface 116 of the inner tubular 110. In the Examples, the distance between the inlet ports 120 and the outlet ports 160 is referred to as the "main element" or "main body".
In Examples 1 to 3, the raised ridges 130 were arranged in two rows of vertical bars with gaps 135, similar to the embodiment of the fluid injection device illustrated in Fig. 3 and Fig. 8.
Testing was performed at temperatures between 200 to 230 C, and pressures ranging from 300 to 450 psi to assess the steam quality as a function of flow rate, injection-steam quality, temperature and pressure. Steam quality used was 100, 90 and 80%, with varying nominal flow rates of about 3, 6 and 12 L/min (equivalent to about 151.2, 302.2 and 604.8 m3/day cold water equivalent (CWE) (assuming 35 fluid injection devices in place)). Measurements of the differential pressure were taken from five different points along the fluid injection devices.
Steam quality was adjusted by injecting cold water (at ambient temperature) into the line before the inlet of the fluid injection device.
The increased area of the annular flow space (118) had a significant effect on the differential pressure. By increasing the cross-sections flow area of Example 1 by 83.6%, the differential pressure, exhibited by Example 3, decreased by a factor of 10.
The testing indicates that most of the pressure drop occurred in the "main element", and the pressure drop through the raised ridges 130. Together, they account for about 85%
of the total pressure dropped. For example, FIG. 9 illustrates the overall pressure drop performance of Example 1. As discussed above, the overall shape of the pressure drop curves are not as would be expected. It is normal for pressure drops to increase exponentially (i.e., in a non-linear manner) with an increase in flowrate for piping systems.
An example of an expected curve is drawn for illustration (not based on actual calculations) in FIG. 9.
The expected pressure drop was lower at low flowrates (e.g., 3 litres/minute) than was observed when testing Examples 1 to 3. The pressure drop through the "main element"
generally follows the shape of an expected pressure drop curve. On the other hand, the pressure drops including the raised ridges 130 have pressure drops that are approximately linear and are not consistent with simple flow theory (see FIG. 9).

Claims (21)

1. A fluid-injection casing section receivable in a wellbore for injecting fluid into a formation, the fluid-injection casing section comprising:
an inner tubular having a first end, a second end, an inner bore and a plurality of inlet ports passing through the inner tubular proximate a first end of the inner tubular;
an outer sleeve having a first end, a second end and a plurality of outlet ports located proximate the second end of the outer sleeve and passing through the outer sleeve, the outer sleeve sized to fit over the inner tubular so that the first end covers the ports in the inner tubular and forms an annular space between the inner tubular and the outer sleeve, said annular space in fluid communication with the plurality of inlet ports and the plurality of outlet ports; and two or more sets of raised ring segments spaced longitudinally apart from each other in between the first and second ends of the inner tubular, each set of the two or more sets of raised ring segments encircling the inner tubular and extending radially outward from an outer surface of the inner tubular into the annular space.
wherein fluid injected into the inner bore of the inner tubular enters the annular space through the inlet ports and is discharged from the fluid-injection casing section through the outlet ports.

2. The fluid-injection casing section according to claim 1, wherein the two or more ring segments comprise one or more circumferentially spaced gaps for allowing fluid communication between a first end side of the ring segment and a second end side of the ring segment such that fluid entering the annular space through the inlet ports flows through the one or more gaps prior to being discharged from the fluid-injection casing section.

3. The fluid-injection casing section according to claim 2, wherein the two or more sets of raised ring segments are adjacent to each other; and wherein the one or more circumferentially spaced gaps are positioned in such a manner as to be misaligned relative to each other such that fluid passing through a gap in one of the two or more ring segments flows circumferentially through the annular space prior to passing through a gap in a next one of the two or more ring segments, prior to being discharged from the fluid-injection casing section through the outlet ports.

4. The fluid-injection casing section according to any one of claims 1 to 3, wherein the outer surface of the inner tubular comprises one or more roughened sections for increasing the frictional effect on a flow of fluid passing thereover.

5. The fluid-injection casing section according to any one of claims 1 to 4, wherein an inner surface of the outer sleeve comprises one or more roughened sections for increasing the frictional effect on a flow of fluid passing thereover.

6. A system for distributing steam in a wellbore in a subterranean formation, the system comprising:
a casing receivable in a wellbore and comprising one or more fluid-injection casing sections according to any one of claims 1 to 5; and one or more injection lines passing through the inner bores of the inner tubular of the fluid-injection casing sections;
wherein the one or more fluid-injection casing sections and the injection lines are configured for injecting fluid into the one or more fluid-injection casing sections through the injection lines, and discharging the fluid from the outlet ports of the one or more fluid-injection casing sections for injecting into the subterranean formation.

7. The system according to claim 6, wherein the wellbore is a horizontal wellbore.

8. The system according to claim 7, wherein the one or more fluid-injection casing sections extend from a heel area of the wellbore to a toe area of the wellbore.

9. The system according to claim 8, wherein the system comprises an injection line near the heel area of the wellbore and a second injection line near the toe area of the wellbore.

10. The system according to any one of claims 6 to 9, wherein the system is used in a steam assisted gravity drainage process.

11. The system according to any one of claims 6 to 9, wherein the system is used in a cyclic steam stimulation process.

12. The system according to any one of claims 6 to 9, wherein the system is used in a steam flood process.

13. The system according to any one of claims 6 to 9, wherein the system is used in a steam assisted gravity drainage (SAGD) process.

14. A fluid-injection casing section receivable in a wellbore for injecting fluid into a formation, the fluid-injection casing section comprising:
an inner tubular having a first end, a second end, an inner bore and a plurality of inlet ports passing through the inner tubular proximate a first end of the inner tubular;
an outer sleeve having a first end, a second end and a plurality of outlet ports located proximate the second end of the outer sleeve and passing through the outer sleeve, the outer sleeve sized to fit over the inner tubular so that the first end covers the ports in the inner tubular and forms an annular space between the inner tubular and the outer sleeve, said annular space in fluid communication with the plurality of inlet ports and plurality of outlet ports; and one or more roughened sections on at least one of the outer surface of the inner tubular or an inner surface of the outer sleeve for increasing the frictional effect on a flow of fluid passing thereover.

15. The fluid-injection casing section of claim 14 further comprising one or more sets of raised ring segments positioned in between the first and second ends of the inner tubular and encircling the inner tubular, each of the one or more sets of raised ring segments comprising one or more circumferentially spaced gaps.

16. The fluid-injection casing section of claim 15, wherein the fluid-injection casing section comprises two or more sets of raised ring segments; and wherein at least one of the roughened sections is between the two or more sets of raised ring segments.

17. A system for distributing steam in a wellbore in a subterranean formation, the system comprising:
a casing receivable in a wellbore and comprising one or more fluid-injection casing sections according to any one of claims 14 to 16; and one or more injection lines passing through the inner bores of the inner tubular of the fluid-injection casing sections;
wherein fluid is injected into the plurality of fluid-injection casing sections through the injection lines; and wherein the fluid is discharged from the outlet ports of the fluid-injection casing sections and injected into the subterranean formation.

18. The system according to claim 17, wherein the wellbore is a horizontal wellbore.

19. The system according to claim 18, wherein the wellbore has a heel and toe area and wherein the one or more fluid-injection casing sections extends from a heel area of the wellbore to a toe area of the wellbore.

20. The system according to claim 19, wherein the system comprises an injection line near the heel area of the wellbore and a second injection line near the toe area of the wellbore.

21. The system according to any one of claims 17 to 20, wherein the system is used in a steam assisted gravity drainage (SAGD) process.