CA2777120A1 - Sagd system and method - Google Patents

Abstract

A system and method is provided. The system has a steam assisted gravity drainage well pair having a steam injection well and a producer well, the steam injection well positioned vertically above and substantially parallel to the producer well, the steam injection well and the producer well being substantially horizontal, and at least one supplemental steam injection well angled relative to the steam injection well and the producer well and passing in between the injection well and the producer well. Steam is injected into the reservoir through the steam injection well and the supplemental steam injection well and producing hydrocarbon from the reservoir using the producer well.

Description

SAUD SYSTEM AND METHOD
The present invention relates to recovering hydrocarbon from a reservoir using steam assisted gravity drainage (S,kGD).
BACKGROUND
Steam assisted gravity drainage (SAGD) is an enhanced oil technology that is used for producing hydrocarbon (typically in the form of heavy crude oil and bitumen) from an oil reservoir. It operates using several Nell pairs that are spaced throughout the reservoir.
Each well pair is formed from a pair of vertically-spaced horizontal wells that are drilled through an oil reservoir. Groupings of several well pairs are often drilled together from a to drilling pad site, such that each of the well pairs is in the group is horizontally spaced from the other well pairs and all of the well pairs from each pad run more or less parallel to one another in the reservoir.
To produce bitumen or heavy crude from the reservoir, steam is injected under high pressure from the wells of the well pair. First, steam is injected from both of the wells of the well pair until fluid communication is established between the top well and the bottom well. Once this communication is achieved, steam is injected predominantly through the top well (or the injection well). This steam is injected into the reservoir where it typically forms a steam chamber extending upwards and outwards from the -injection well. The steam in the steam chamber heats hydrocarbon in the reservoir, lowering its viscosity. This heated hydrocarbon with its lowered viscosity can then drain downwards (aided by gravity) where it can drain into the lower horizontal well (the producer well of the well par) to be produced from the lower horizontal well.
Because there are usually a series of horizontally-spaced well pairs passing through a reservoir where hydrocarbon is to be produced, each well pair will form its own steam chamber. Each well pair passing through the reservoir typically runs parallel to one or more adjacent well pairs. When steam is injected into the reservoir using the top injection wells of the each well pair, each well pair will form its own steam chamber extending upwards and outwards from the injection well.
This method of producing hydrocarbons (such as heavy crude or bitumen) from a reservoir using a series of horizontally spaced well pairs assumes that the reservoir has relatively uniform conditions, with the flow properties of the reservoir and the characteristics of the hydrocarbon being consistent throughout the entire length and width of reservoir where the well pairs are placed. or that variations will not affect the performance of the wells. However, reservoirs are rarely consistent in the real world and these inconsistencies in the conditions of the reservoir and the inability of the SAGD well pairs to address these inconsistencies can result in an inefficient producing of the hydrocarbon from the reservoir or even result in hydrocarbon that could be producible being left in the reservoir, Conditions in a reservoir can vary greatly throughout the reservoir For example, permeability of a reservoir can vary quite significantly throughout the reservoir. Over top of one well pair or even across only a portion of the length of one well nore, the permeability of the reservoir may he relatively low causing poor steam penetration and therefore poor production of bitumen from this area of the reservoir. However, because the steam must be injected under one pressure in each injection well at the ground surface there may be little or no way in a conventional SAGD system to take into account this region of higher permeability by injecting more steam into this specific region. This can result in some of the hydrocarbon remaining unproduced from this lower permeable to region of the reservoir or requiring more steam than necessary to be injected through the entire reservoir to produce the hydrocarbon from this area of lower permeability. This is especially true where the lower permeability occurs over only a portion of a length of a well pair with the reservoir having higher permeability conditions along the other portions of the length of the well pair, since the steam cannot typically be injected at.
different rates along a single injection well after the injection well is in place.
In addition to the possible variability in the permeability of the reservoir in different areas, a number of other factors can affect the effectiveness of a conventional SAGD
system. Changes in water saturation heterogeneity and characteristics can vary over the reservoir causing uneven production of bitumen from a SAGD system. Viscosity of the bitumen itself can vary over the reservoir, with some of the bitumen in the reservoir having a higher viscosity in certain areas than in others. All of these variations in the conditions of the reservoir can be hard if not impossible to address using horizontally spaced well pairs, alone.
DESCRIPTION OF THE DRAWINGS
A preferred embodiment of the present invention is described below with reference to the accompanying drawings, in which:
FIG. 1 is a schematic of a SAGD well pair;
FIG. 2 is a schematic illustration of a steam plume formed using an injection well;
FIG. 3 is a schematic illustration of steam plumes formed using a pair of adjacent well pairs;
FIG. 4 is a schematic illustration of a SAGD well pair with supplemental injection wells;
FIG. 5 illustrates the startup of steam injection of the SAGD system shown in FIG. 4;
is FIG. 6 illustrates the growth of the steam chamber of the SAGD system shown in FIG. 4;

FIG. 7 illustrates a mature steam chamber formed using only the injection well of the SAGD system shown in FIG. 4;
FIG. 8 illustrates a steam chamber when steam is injected into it using supplemental injection wells of the SAGD system shown in FIG. 4;
FIGS. 9-10 illustrates the steam chamber in FIG. 8 as steam continues to be injected into the steam chamber using the supplemental injection wells;
FIG. 11 illustrates a well field having a number of well pairs and a number of supplement injection wells where each supplemental injection well intersects with only a single well pair;
FIG. 12 illustrates a long well pair with supplemental injection wells; and FIGS. 13-18 illustrates the steam chamber in FIG. 12 as steam continues to be injected into the steam chamber using the supplemental injection wells; and FIG. 19 illustrates a schematic side view of a well pair with a low placed supplemental injection well.

DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS
Referring to FIG. I, a conventional SAGO well pair 10 is shown in a reservoir 50. The reservoir 50 can be provided below a ground surface 55 and contain hydrocarbon such as heavy crude or bitumen that cannot be produced using the same methods used for conventional oil. The SAGD well pair 10 is provided passing substantially horizontally through the reservoir 10, typically below the majority of the hydrocarbon in the reservoir 50.
The SAGD well pair 10 is made up of an injection well 20 and a producing well 30. The injection well 20 is provided vertically spaced above the producing well 30.
Steam is injected into the reservoir 50 from the injection well 20 and hydrocarbon that has drained downwards after being heated by the steam collects in and is produced from the producer well 30.
The injection well 20 and the producing well 30 each start from the ground surface 60 where they initially run substantially vertically until a heel 22, 32. From the heel 22, 32 IS both the injection well 20 and the producing well 30 run substantially horizontal through the reservoir 50 until a toe 24, 34 of each well 20, 30.
FIG. 2 illustrates a steam chamber 60 formed using the injection well 20 of the well pair 10. Initially, steam is injected through both the injection well 20 and the producer well 30 until steam places the wells 20, 30 in fluid communication, at which time, steam is predominantly injected through the injection well 20. The steam chamber 60 originates at the injection well 20 and as the steam rises from the injection well 20 it will spread outwards forming an inverted cone shape when viewed along the direction of the horizontal wells 20, 30. Hydrocarbon in the reservoir that is located in the steam chamber 60 is heated by steam and, with the viscosity of this hydrocarbon sufficiently lowered, begins to drain towards the producer well 30.
The steam chamber 60 forms a theoretical drainage zone 65 from which hydrocarbon can be produced by the well pair 10. This drainage zone 60 can be visualized as a rectangle in FIG. 2 or a long box shaped pattern along the length of a well pair 10. The drainage i0 zone 65 will be the section of the reservoir 10 that the well pair 10 affects.
Typically, a series of horizontally spaced well pairs 10 are used to produce hydrocarbon from the reservoir. The well pairs 10 are spaced apart horizontally with each well pair 10 running substantially parallel to adjacent well pairs 10. FIG. 3 illustrates a two (2) adjacent well pairs 10A, 10B. Each well pair 10A, 10B is shown in the direction the well pair 10A, 10B is running.
Steam chambers 60A, 60B are formed using the injection wells 20A. 20B of each well pair IOA, 10B. Each steam chamber 60A, 60B rises upwards and outwards from the injection well 20A, 20B that is creating the steam chamber 60A, 60B. If the well pairs 10A, 10B are positioned properly from one another, the steams chambers 60A, 608 will mingle as they rise upwards.
The drainage zones 65A, 658 of each well pair 10A, 10B will lie adjacent to one another. but each steam chamber 60A, 60B should be contained within a single drainage zone 65A, 658. With the first steam chamber 65A created by the first well pair enclosed with the first drainage zone 65A and the second steam chamber 658 created by the second well pair 1.0B enclosed within the second drainage zone 65B.
FIG. 4 illustrates the well pair 10 provided in the reservoir 50 where supplemental injection wells 70A, 70B have been provided. With the well pair 10 in place and the injection well 20 positioned vertically above and parallel to the producer well 30, supplemental injection wells 70A, 70B can be provided. These supplemental injection wells 70A, 70B can be substantially horizontal and run at an angle to the well pair 10. In one aspect, the supplemental injection wells 70A, 70B can pass substantially perpendicularly to the well pair 10. The supplemental injection wells 70A, 7013 can pass between the injection well 20 and the producer well 30 so that, where the supplemental injection wells 70A, 70B intersects with the well pair 1.0, the supplement injection wells 70A, 70B are below the injection well 20 but above the producer well 30.

Although FIG. 4 illustrates two (2) supplemental injection wells 70A, 70B, any practical/desirable number of supplemental injection wells can he provided related to the well pair 10.
In one aspect, the supplemental injections wells 70A, 70B can be positioned so that they pass much closer to the producer well 30 than the injection well 20 of the well pair 10.
There is no requirement for the supplemental injection wells 70A, 70B to be of the same length. In some cases, it may be desirable for the supplemental injection wells 70A, 70B
to be of different lengths. This allows for applications with odd-shaped portions of the development area as dictated by the geology of the reservoir and can eliminate the need to avoid portions of the potential developmental area where the pay thickness for example is either generally less than the optimum or odd-shaped portions of the oil formation.
Referring to Fig. 19, in one aspect a supplemental injection well 270 can be positioned so that it runs in approximately the same horizontal plane as a. producer well 230 of a well pair 210. Where the supplemental injection well 270 intersects the producer well 230, the supplemental injection well 270 can be routed to run over top of the producer well 230 before once again being routed to run in a plane substantially parallel to the producer well 230. Therefore, a portion of the length of the supplemental injection well 270 will be positioned in substantially the same plane as the producer well 230 except for where the supplemental injection well 270 passes over the producer well 230. In this manner, the supplemental injection 270 well can be placed much closer to the producer well 230 than the injection well 220 of the well pair 210.
With the supplement injection wells 70A, 70B in place, a steam chamber can be generated in the reservoir 50 to heat the hydrocarbon and cause it to drain towards the producer well 30. The steam chamber can be formed in one of two ways: by first creating a conventional steam chamber and then adding steam using the supplemental injection wells 70A, 70B; or by injecting steam into the reservoir 50 through the injection well 20 and the supplemental injection wells 70A, 708, simultaneously.
in in a first method, the injection well 20 of the well pair 10 can be first used to create a conventional steam chamber and then the supplemental injection wells 70A, 708 can he used to inject additional steam into the steam chamber altering the shape and heat of the steam chamber. Referring to FIG. 5, steam can be injected into the reservoir using the injection well 20 of the well pair 10 after steam has been injected through both to injection well 20 and the producer well 30 to place the injection well 30 and producer well 20 in fluid communication. At this point, no steam is injected into the reservoir 50 using the supplemental injection wells 70A, 708. In this manner, a steam chamber 100 begins to form having the configuration of a steam chamber that is created using a well pair 10 alone.

As steam continues to be injected into the reservoir 50 using only the injection well 20 of the well pair 10, the steam chamber 10 will continue to grow in size in the reservoir 50 as shown in Fig. 6. Eventually, the steam chamber 100 will reach it mature size as shown in FIG. 7. At this point, the steam chamber 100 should resemble the steam chamber formed by a SAGD well pair alone since only the injection well 20 has been used to inject steam into the reservoir 50 and no steam has been injected into the reservoir by the supplemental injection wells 70A, 70B.
With the steam chamber 100 reaching maturity for a conventional SAGD well pair 10 as shown in FIG. 7, additional steam can then be injected into the existing steam chamber 100 using the supplemental injection wells 70A, 70B. FIG. 8 illustrates the changes in the steam chamber 100 as a result of steam starting to be injected into the reservoir 50 using the supplemental injection wells 70A, 70B. Eventually, as steam continues to be injected into the reservoir 100 by the supplemental injection wells 70A, 70B
the shape of the steam chamber 100 can be altered as shown in FIGS. 9 and 10.
IS In a different method, the steam chamber can be formed by injecting steam into the reservoir 50 using the injection well 20 of the well pair 10 and the supplemental injection wells 70A, 70B, simultaneously. In this manner, the operator of the steam injection can have much greater control over the injection of steam into the reservoir including during the growth of the steam chamber or during recovery of the hydrocarbon.

In some applications it may be possible to initiate communication between the primary well pair 10 while no fluid injection occurs into the supplemental injection wells 70A, 70B. This communication can be monitored with measurement tools from within the supplemental injection wells 70A, 70B because the supplemental injection wells 70A, 70B are open to the main steam chamber. One can then decrease fluid injection into the injector well 20 while commencing injection through the supplemental injection wells 70A, 708 to activate additional steam chambers along these locations. This sequence can be repeated as many times as desired and used to control steam chamber growth in multiple dimensions and locations along the well pair 10. By evaluating different combinations of operating sequences, an operator can determine the most rapid and effective steam chamber growth pattern that provides the best strategy as determined from performance parameters.
FIGS, 4-10 illustrate the steam chamber 100 when there are two supplemental injection Wells 70A, 70B positioned as shown in the figures. However, by varying the position and Is number of supplemental injection wells, the steam chamber can be altered providing the ability to tailor the eventual steam chamber as desired based on the characteristics of the reservoir. In this manner, supplemental injection wells can be provided along the well pair where it is desired to inject more steam into the reservoir. This can be done to account for conditions that occur in specific regions of the reservoir to help address these conditions.

Referring again to FIG. 2, the use of the supplemental injection wells 70A, 70B can be used to increase the size of the steam chamber 100 in the theoretical drainage zone 65 surrounding each well pair 10. Rather than simply have a roughly cone shaped steam chamber 60 (as shown in FIG. 2), the injection wells 70A, 708 can be used to increase the volume of the steam in the drainage zone 65, better filling the boundaries of the drainage zone 65 and allowing more hydrocarbon to be recovered from the drainage zone 65 associated with a well pair 10. It can also increase the temperature of the steam in the steam chamber around the boundary of the steam chamber.
Additionally, the use of the supplemental injection wells 70A, 70B can improve a to reservoirs steam/oil ratio. Hydrocarbon reservoirs are evaluated based on a steam/oil ratio to determine how viable a reservoir is for SAGD hydrocarbon recovery.
The amount of steam required to recover hydrocarbon in a reservoir is used to determine this steam/oil ratio. The lower the ratio the potentially more profitable the reservoir is for a SAGD site. Needing more steam to recover the hydrocarbon in a reservoir, such as in cases where the permeability of the reservoir is relatively low or the hydrocarbon is relatively viscous, causes this ratio to increase. The supplemental injection wells 70A, 708 can inject steam into the reservoir at specific locations. This can reduce the amount of steam needed overall for the reservoir. With a conventional SAGD well pair alone, steam can only be injected through the injection well requiring additional steam to have to injected along the entire length of the well pair, even if it is only required at very specific locations along the well pair. By using one more supplemental injection wells 70A, 70B, steam can be directed where it is required in the reservoir, allowing a relatively normal amount of steam to be injected through the injection well of the well pair. The supplemental injection wells 70A, 70B can also lower this steam/oil ratio by increasing the amount of hydrocarbon recovered with a well pair in certain circumstances. By using the supplemental injection wells 70A, 70B to increase steam in specific locations along the well pair, more hydrocarbon could be recovered from these areas than normally would be. This can allow the same amount of steam (or slightly more) than what would normally be used to recover more hydrocarbon, thereby increasing the amount of oil recovered and reducing the steam/oil ratio for a reservoir.
The supplemental injection wells 70A, 70B can also be used when the reservoir is relatively short and the well pair 10 is relatively close to the ground surface or a low saturation zone (thief zone) lies relatively close above the well pair 10.
Injecting the steam through the injector well 20 into the reservoir at too high a pressure can result in is the steam reaching the ground surface or low saturation zone. When it reaches this point, the steam will tend to travel upwards in the reservoir to the ground surface or the low saturation zone rather than spreading out. This can cause the steam to be narrower than it ideally should. However by using the supplemental injection wells 70A, 70B, steam can be injected through both the injection well 20 and the supplemental injection wells 70A, 70B at lower pressure but at a similar volume than it would be through just the injection well 20 alone. This lower pressure of the steam in the reservoir can delay the time it takes for the steam to reach the ground surface of the low saturation zone, causing the steam to spread out and the steam chamber to be wider than it would if higher pressure steam was injected through the injector well 20 alone.
In addition to the supplemental injection wells 70A, 70B improving the steam chamber that is formed by the well pair 10, injecting steam into the reservoir using the supplemental injection wells 70A, 70B can cause micro-steam chambers or steam chamberlets to form. These steam chamberlets can form from the intersection of the primary steam chamber along the main well-pair 10 and steam chamber formed alone the to supplemental injection wells 70A, 70B. These steam chamberlets can be very dynamic.
Once formed, these steam chamberlets can be manipulated by the injection of different -ratios of steam and other injectants through the supplemental injection wells 70A, 70B
and can be made to grow independently to contact new bitumen, adapt to the geological characteristics of the reservoir in the affected location, and effect mobilization and recovery in areas previously untouched by the primary steam chamber.
Although FIGS. 4-10 show a single well pair 10 used with the supplemental injection wells 70A, 70B, the reservoir would usually have a number of horizontally spaced and substantially parallel well pairs (not shown). Each supplemental injection well 70A, 70B
would then run substantially perpendicular and between the injection well and the producer well of each of the well pairs. In this manner, each supplemental injection well 70A, 708 would add steam to the steam chamber formed by each well pair.
Although steam is described as being the principal injectant for the injector wells 20 and the supplemental injections wells 70A, 70B, other fluids could be injected in addition to the steam. These could include an appropriate combination of: steam: non-condensible gases such as methane, nitrogen, etc.; petroleum solvents such as propane, butane, etc.;
and flue products of combustion including CO2. The use of these fluids in addition to the steam allows the operator to achieve volumetric conformance, transport the steam away from the interior parts of the chamber to affect unrecovered oil as well as solvents to to increase steani chamber size by mobilization by solvent extraction and effect greater oil recovery. These approaches help to further reduce the steam-oil ratio.
The volume/combination of injectants into each supplemental injection well 70A, 70B
can be adjusted in relation to its location and reservoir attributes.
The flexibility provided by the supplemental injection wells 70A. '70B
(compared to the conventional SAGD well pair 10) allows for sequencing of injection of combinations of steam, solvents, condensable and non-condensible gases as may be desired or determined from simulation to the extent that they are useful for growing the steam chamber both along the primary well pair 10 and also along the trajectories of the supplemental injecting wells 70A, 70B. Different sequencing of injection into the main injector well 20 as well as the supplemental injection wells 70A, 70B will produce different steam chamber growth patterns. Such manipulation may be necessary for example to slow down the vertical growth of the steam chamber along the well-pair 10 and increase lateral growth along the supplemental injection wells 70A, 70B and increase the recovery factor.
FIG. 11 illustrates a field of well pairs 110 where a number of supplemental injection wells 170 are provided. Well pairs 110, each having an injection well 120 and a producer well 130, are positioned running horizontally. The well pairs 110 are spaced apart and run substantially parallel to one another.
A number of supplemental injection wells 170 can be provided. However, rather than w each supplemental injection well 170 mining substantially perpendicular to all of the well pairs 110, each supplemental injection well 170 can be substantially perpendicular and pass below the injection well 120 and above the producer well 130 of only a single well pair 110. In this manner, the supplemental injection wells 170 can be used to increase the steam at a target point at a single point alone only a single well pair 110 rather than all of the well pairs 110.
The supplemental injection wells can be drilled at the same time the well pairs are drilled.
However, in many cases it will be beneficial to determine how effectively the horizontally-spaced substantially parallel well pairs are able to produce from a reservoir.
After it is has been determined how effective the well pairs alone may be in the reservoir, supplemental injection wells can be provided in locations in the reservoir that require increased steam for increased hydrocarbon recovery from these areas of the reservoir.
In one aspect, the supplemental injection wells can constructed by first drilling a vertical well through the reservoir. Then after the vertical well is drilled, running a horizontal lateral off of the vertical well. In this manner, the vertical well can be logged to determine the vertical characteristics of the reservoir where the vertical well portion of the supplemental injection well is drilled.
In one aspect, the locations of the supplemental injection wells can be determined using data obtained from the drilling of the well pairs. First, the well pairs 1.0 can be drilled through the reservoir 50 so that the well pairs 10 are substantially parallel and of substantially equal length as is typically done in conventional SAGD practice.
Geological logs can be obtained from drilling the well pairs 10 and these geological logs reviewed to determine any abnormalities in the reservoir 50, shale intervals and any other features in the reservoir that may restrain the flow of steam and/or hydrocarbon and result in a lower recovery of hydrocarbon from reservoir 50.
Using the results of the analysis of the geological logs, target points along the well pairs 10 can be identified. These target points can be chosen to try and address any geological features observed along the well pairs 10 as well as for geometric balance Since the placement of the supplemental injectors is designed to achieve specific process objectives including lowering the steam-oil ratio compared to a standard SAGD
well-pair, as well as providing operation control and flexibility in steam placement and management to achieve these performance objectives as well as address specific reservoir and geological features not possible with conventional well-pair. These factors therefore have an overarching influence in the number and location of the target points determined for placement of supplemental injection wells. For geometrical balance the separation of the supplemental injecting wells at both entrance and end of the horizontal well pairs should be such as to ensure maximum effectiveness in achieving coverage of the entire to well pattern at both ends of the well pair.
In cases where the placement of the supplemental injection wells is well-pair centric therefore it may be desirable in certain circumstances to place fewer supplemental injection wells along one or more well-pairs than the others in a pad of several well-pairs, depending on the extent the supplemental injections wells is required to address production performance objectives.
Furthermore, the supplemental injection wells provide access to reservoir not easily accessible with the conventional well-pair, the greater the number the more reserves are contacted, and the greater the ability to distribute the injected steam, further reducing the steam-oil ratio of the well-pair, increasing the recovery factor, accelerating the recovery process. The appropriate number of supplemental injection wells can be established through numerical simulation.
At each selected target point along the well pairs 10 a supplement injection well 70 can be drilled.
In addition to or alternatively to the geological well profiles of the well pairs, the target points along the well pairs could be determined by from the analysis of numerical simulation results to try and optimize the locations of the supplemental injection wells.
It is common practice to use commercially available numerical reservoir simulation software to establish the prospectivity of a SAGE. operation in any particular reservoir, lo especially when the first application of the process is contemplated.
The reservoir and fluid properties characteristic of the target formation obtained from cores and well logs are used to populate a reservoir model for use in numerical simulation of a life-time of SAGE) operation to predict the performance of a SAGD well-pair. The result of such simulation often include process performance parameters such as oil rates, recovery factor, steam-oil ratio, cumulative production over the time of operation.
Numerical simulation will be even more critical with the addition of supplemental injection wells, firstly to determine the number of supplemental injection wells needed along a well-pair in order to achieve the desired performance objectives. A more refined series of simulation will be required after the well-pair is drilled and an improved set of reservoir properties have been gathered and such model run is then used modify or improve the positioning of the target points where supplemental injection wells will be provided.
With the drilling of the supplemental injection wells, additional sets of geologic and reservoir data will be available providing more detail and more specific to each supplemental injection well location. All the accumulated data is then fed into the numerical model to improve the performance prediction and develop improved developmental and operating strategies. Where such model runs are often not repeated with subsequent extension to new pads in application of conventional SGAD, the uniqueness of each well-pair and the opportunity for improved performance dictates the benefit of on-going integration of numerical modelling with the field production operation of the well-pair.
Referring again to FIG. 4, the supplemental injection wells 70A, 70B can be used right after a field of well pairs 10 is drilled or the supplemental injection wells 70A, 70B can be drilled long after the well pairs 10 have already been used. to recover some of the hydrocarbon from a reservoir. Rather than designing a new field and installing the supplemental injection wells before the reservoir in the field is first produced, the supplemental injection wells 70A, 70B can be used to increase the productivity of an existing field of well pairs 10 or could be used with a reservoir where production has been ended to go back in and produce hydrocarbon that was not recovered from the reservoir using the well pairs alone. After a reservoir has already been produced using well pairs 10 alone, supplemental injection wells 70A, 70B can be then drilled and the well pairs 10 and the supplemental injection wells 70A, 70B used to try and obtain additional hydrocarbon from the reservoir with the supplemental injection wells 70A, 70B being placed to try increase the steam in certain portions of the reservoir were hydrocarbon was under produced previously. This allows the supplemental injection wells 70A, 70B to be backwards compatible with existing well pair 10 fields.
By first drilling vertical wells and the forming the supplemental injection wells 70A, 70B
as horizontal laterals from these vertical wells, these vertical wells can be logged to provide useful information for the current state of the reservoir and the concentration of to remaining hydrocarbon. =
In one aspect, if the supplemental injection wells 70A, 70B are being used to retrofit and existing field of well pairs 10. The supplemental injection wells 70A, 70B can be placed as close as possible to the producer well 30 of the well pair 10. In this manner, steam injected into the reservoir 50 from the supplemental injection well 70A, 70B
can cross the steam chamber at its narrowest point. Because the reservoir has already been produced using the well pair 10. The space within the previous steam chamber will have much of the hydrocarbon recovered from it and will therefore be highly permeable. This area will cause steam to be more easily injected into the reservoir in this zone of higher permeability losing potential steam that could be used to expand beyond the zone where the previous steam chamber was formed. By running the supplement injection wells 70A, 70B through the old steam chamber at a narrower spot, less steam should be released into the old steam chamber.
In addition to injection of additional steam into the reservoir, the supplemental injection wells 70A, 70B can be equipped with pressure and temperature monitoring devices. This can allow the supplemental injection wells 70A, 70B to serve a useful role in the development of an extensive monitoring program through different stages of the recovery operation. Measurements recorded could include progressive heating at different locations along the well pair 10 as well as steam chamber development along the supplemental injection wells 70A, 70B. Pressure monitoring devices could be installed to to determine operating pressures of the supplemental injection wells 70A, 70B. Pressure monitoring can be especially useful where there is a requirement to control peak steam chamber pressures in a reservoir because too high a pressure can comprise the stability of the cap rock.
FIG. 12 illustrates a relatively long well pair 210 with supplement injection wells 270 35 being provided along the length of the well pair 210. In relatively long well pairs 210, such as 500-1500 meters or longer, the steam being injected by the injection well 220 can vary significantly over the length of the well pair 210. Steam injected into the reservoir 250 near the heel 212, of the well pair 210 can be of a better quality than the steam injected near the toe 214 of the well pair 210 because the steam being injected near the 20 toe 214 must travel the entire length of the injection well 220 of the well pair 210.

By drilling a number of supplemental injection wells 270 the quality of steam along the entire length of the well pair 210 can be improved in addition to allowing the amount of steam being injected in certain places along the well pair 210 to be improved.
The supplemental injection wells 270 can alter the steam chambers formed by the more conventional well pair 210. Referring to FIG. 13, steam can be injected into the reservoir using the injection well 230 of the well pair 210. At this point, no steam is injected into the reservoir 250 using the supplemental injection wells 270. In this manner, a steam chamber 200 begins to form having the configuration of a steam chamber that is created using a well pair 210 alone.
As steam continues to be injected into the reservoir 250 using only the injection well 230 of the well pair 210, the steam chamber 210 will continue to grow in size in the reservoir 250 as shown in Fig. 14. Eventually, the steam chamber 200 will reach it mature size as shown in FIG. 15. With the steam chamber 200 reaching maturity for a conventional SAGD well pair 210 as shown in FIG. 15, additional steam can be injected into the steam chamber 200 using the supplemental injection wells 270 as shown in FIG. 16.
FIG.
17illustrates the changes in the steam chamber 200 as a result of steam starting to be injected into the reservoir 250 using the supplemental injection wells 270.
Eventually, as steam continues to be injected into the reservoir 200 by the supplemental injection wells 270 the shape of the steam chamber 200 can be altered as shown in FIGS. 18.

The foregoing is considered as illustrative only of the principles of the invention.
Further, since numerous changes and modifications will readily occur to those skilled in the art, it is not desired to limit the invention to the exact construction and operation shown and described, and accordingly, all such suitable changes or modifications in structure or operation which may be resorted to are intended to fall within the scope of the claimed invention.