Patent Application
20120205096
The present invention relates generally to the displacement of water from a porous and permeable formation. More particularly, the present invention relates to a method for isolating a displacement zone within a porous and permeable formation, and then replacing water in the isolated zone with a non-condensing gas.
Many commercial operations require access to underground reservoirs, including mining operations, oil and gas production, natural gas storage, compressed air energy storage, and carbon dioxide sequestration. In some cases, gaining access to such reservoirs would require the production of water from formations within or around the reservoir. However, producing such water is a challenge, particularly when the porous and permeable reservoir is very large, and when the water is in hydraulic contact with other resources.
Of particular interest in Canada's oil sands, certain bitumen-containing zones or formations of interest for in situ production may be overlain by an aquifer. In such situations, application of in situ recovery techniques to harvest the underlying bitumen may be less economically feasible in the presence of such overlying water. Furthermore, if the water zone or aquifer overlying the formation is potable, certain regulatory requirements must be observed to maintain the potable water supply.
Notably, when a water zone or aquifer is in hydraulic contact with an oil sand, the efficiency of any in situ recovery operation aimed at harvesting petroleum from the underlying oil sand could be seriously compromised.
Thus, irrespective of the quality of the water, the hydraulic contact of the oilsand formation with significant amounts of overlying water is likely to be prejudicial either to conservation of the potable water resource and/or to operational efficiency if the petroleum resource is to be extracted.
In accordance with a first aspect of the invention, there is provided a method for displacing water from a target region of a permeable geological formation with a volume of injected gas, the method comprising the steps of: identifying a target region of the formation from which water is to be displaced; providing a series of barrier wells along permeable boundaries of the target region; providing a gas injection well within the target region; injecting fluid into the barrier wells to establish a gas-confining barrier around the target region; providing a production well within the gas-confining barrier; and operating the gas injection well and the production well concurrently to effect a net production of water from the target region while maintaining the gas-confining.
In an embodiment, the method further comprises the step of monitoring fluid composition of the geological formation outside the target region.
In another embodiment, the method further comprises the step of controlling fluid injection into the barrier wells and from the production well to maintain the hydraulic pressure at the gas-confining barrier in excess of the hydraulic pressure within the target region, thereby limiting escape of gas from the target region.
In another embodiment, the method further comprises the step of monitoring gas production from the production well. The rate of water production from the production well may be controlled to reduce gas production from the production well.
In a further embodiment, the method comprises the step of recovering a resource from a formation beneath the target region. The method may comprise the step of producing hydrocarbons from a hydrocarbon-bearing formation proximal to, or beneath, the target region. The hydrocarbon production may involve steam injection into the formation beneath the target region.
In an embodiment, the method comprises repeating each step in respect of a further target region of the permeable formation to displace water from said further target region, while continuing to operate said barrier wells, gas injection well, and production well.
In various embodiments, the gas may be air, carbon dioxide, nitrogen, methane, exhaust gas, enriched air, or oxygen.
In another embodiment, the method further comprises the step of directing produced water from the production well to the barrier well(s) for injection. The gas-confining barrier may be maintained by continuous or periodic fluid injection into the barrier wells.
In accordance with a second aspect of the invention, there is provided a well system for use in removal of water from a target region of a permeable geological formation, the well system comprising: a series of fluid injection wells defining a boundary along a target region within the permeable geologic formation, the injection wells operable to establish a hydraulic pressure barrier along said laterally permeable boundary; one or more gas injection wells operable to deliver pressurized gas into the target region; and one or more production wells located within the target region, the production wells operable independently from operation of the injection wells to produce water from the target region.
In an embodiment, the well system comprises one or more horizontal, deviated, or branched wellbores.
In one embodiment, the gas injection is a horizontal, deviated, or branched wellbores. The gas injection well may extend outside the target region to supply injected gas to a further target region within the formation.
In an embodiment, the well system comprises a source of pressurized gas. In various embodiments, the pressurized gas may be air, carbon dioxide, nitrogen, methane, exhaust gas, enriched air, or oxygen.
In accordance with a third aspect of the invention, there is provided a system for displacement of water from a permeable geological formation, the system comprising:
In an embodiment, the series of fluid injection wells comprises one or more horizontal, deviated, or branched wellbores.
In an embodiment, the series of fluid injection wells comprises one or more horizontal, deviated, or branched wellbores.
In one embodiment, the gas injection is a horizontal, deviated, or branched wellbores. The gas injection well may extend outside the target region to supply injected gas to a further target region within the formation.
In an embodiment, the series of fluid injection wells comprises a source of pressurized gas. In various embodiments, the pressurized gas may be air, carbon dioxide, nitrogen, methane, exhaust gas, enriched air, or oxygen.
In an further aspect, a method is provided for displacing fluid from a target region within a permeable geological formation, the method comprising the steps of:
In an embodiment, the method further comprises the step of providing communication means between the permeable geological formation and a source of gas at surface. The source of gas may be ambient air.
In an embodiment, the method further comprises the step of controlling fluid injection into the barrier wells and from the production well to maintain the hydraulic pressure barrier in excess of the hydraulic pressure within the target region, thereby limiting escape of gas from the target region.
The method may further comprise the step of monitoring gas production from the production well.
In an embodiment, the method further comprises the step of controlling the rate of water production from the production well to reduce gas production from the production well. The produced water may be directed to the barrier well(s) for injection.
In a further embodiment, the method further comprises recovering a resource from a formation beneath the target region. The method may comprise the step of producing hydrocarbons from a hydrocarbon-bearing formation proximal to, or beneath, the target region. The hydrocarbon production may involve steam injection into the formation beneath the target region.
The method may further comprise repeating each step in the method in respect of a further target region of the permeable formation to displace water from said further target region, while continuing to operate said barrier wells, gas injection well, and production well.
Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.
The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawings will be provided by the Office upon request and payment of the necessary fee.
Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures, wherein:
a-e is a series of three dimensional computer simulated schematics depicting the well configuration and progression of an example displacement operation.
Generally, the present invention provides a method and system for efficiently displacing a volume of water from a permeable underground reservoir with an amount of pressurized gas.
In sloping formations, simple displacement of water with gas is typically accomplished, at least in part, by exploiting the inherent difference in density and viscosity between water and gas. That is, injection of gas at an upslope location will tend to displace water in a down-slope direction for production. However, the efficiency of this displacement process can be poor due to the viscosity difference between the gas and the water which can lead to the gas moving horizontally outward from the point of injection most rapidly, at or near the top of the formation. Under these circumstances the water displacement can take a very long time and cannot be accelerated by injecting the gas faster. The present methods permit isolation of a target region within the formation, and permits immiscible displacement of water from the region. Such isolated displacement exploits the density and viscosity contrast between the gas and water phases to more quickly and efficiently displace water to surface.
In addition, when the underground reservoir is of a geologic structure not conducive to simple gas displacement, the present methods allow hydraulic isolation of the reservoir, or a segment thereof, such that water can be efficiently replaced with gas within the isolated segment. When the present method is used to sequentially isolate and displace manageable segments of a larger porous reservoir, greater efficiencies are realized.
Specifically, in an environment involving an oil sand or bitumen zone with an overlying water zone or aquifer that is in hydraulic contact with the oil sand, the replacement of this overlying water by a gas can be problematic. For example, Canada's oil sands deposits or reservoirs consist, on a local scale, of substantially horizontal strata. Therefore, one cannot typically rely on a slope to aid in displacement of the water by a gas. Rather, in the substantially horizontal oil sands formations, gas injected into the formation or aquifer will dissipate over the water, moving horizontally outward from the point of injection most rapidly, at or near the top of the water. As a result, if the aquifer covers an extensive horizontal area, the injected gas will form a very thin gas layer on top of the water within the formation. Under these conditions, with no natural physical constraints on horizontal movement of the injected gas, attempts to move the gas-water contact downward and thereby effect pressurized removal of the water from the aquifer will require correspondingly very large volumes of gas. Such gas injection is not practical, due to increased time and cost to achieve suitable volumes of water production. Furthermore, if the aquifer outcrops at some point into a surface water feature, such as a lake or river, then this approach may be ineffective and also unacceptable environmentally as it could result in migration of gas along the top of the aquifer to the point of aquifer outcrop and subsequent emission into the atmosphere. Moreover, produced water would be quickly replaced due to the existence of a high water table in this scenario.
The presently described system and method for water displacement allows a displacement zone or target region within a substantially horizontal aquifer or other porous and permeable formation, to be hydraulically isolated from the surrounding geology. This is accomplished by placement and operation of a series of water injection wells around the target region, otherwise referred to as barrier wells, concurrent with water production from within the target region. Suitable operation of these wells will establish a hydraulic pressure barrier around the target region. Once established, continued injection of water into the barrier wells, along with controlled gas injection and water production to/from the isolated target region, will allow a significant amount of water to be replaced with gas.
The barrier wells are operated while taking into consideration the density contrast, viscosity contrast, and immiscibility of the injected gas and water. These properties of the native and injected fluids will inherently improve efficiency of displacement, and will reduce coning and fingering of injected gas. In addition, the injection and production wells are operated to prevent migration of injected gas past the established barriers, and to reduce gas coning or fingering into the water production well.
Once the barrier wells have been established to create one or more isolated target regions across the aquifer, pressurized non-condensing gas is injected into each target region. The relative positions of the barrier wells (and the hydraulic barriers which they create), the gas injection well, the water production well, and the manner in which these wells are operated, prevents uncontrolled lateral gas override and, in the case of an outcropping aquifer, avoids the potential atmospheric emission of injected gas. In simulations to date, it appears that the natural tendency of injected gas to channel or cone into the produced water stream can be limited and/or prevented by appropriate operational monitoring and control. That is, pressurized gas is injected into the isolated target region to displace the water immiscibly and under conditions of highly adverse mobility ratio.
Further, a method of producing water from a substantially horizontal, deep water zone or aquifer is provided. A target region is hydraulically isolated, and pressurized gas is injected into each target region. The laterally constrained gas injection provides concentrated displacement of water with gas, limiting lateral gas migration, to allow a greater degree of control over the efficiency of displacement, and associated water production. As the target region is hydraulically isolated from the remainder of the aquifer, a staged approach to resource management is possible. For example, a particular vertical segment of a porous formation may be isolated, drained, and the underlying resources extracted. An adjacent region may be handled independently, allowing greater efficiency, flexibility, and conservation of resources in operational planning.
When referring to the injection, production, or barrier wells discussed herein, it should be noted that these wells may be vertical wells, horizontal wells, or wells that are drilled directionally along a selected trajectory, or varying combinations of each. The operation would typically be planned and optimized by computer simulation, to determine the most appropriate well configuration for each application, target region, or reservoir. Such wells are operated to prevent horizontal gas migration beyond the target region. This may also be referred to as hydraulic isolation, providing a gas-confining barrier (which may be a natural geological barrier or by the suitable operation of barrier wells), or as providing a hydraulic pressure barrier.
The present description refers to displacement of water from a porous and permeable reservoir, or portion thereof, which reservoir will have natural boundaries. that limit the porous and permeable formation. Where a natural geologic boundary is present adjacent a segment to be isolated and displaced of water, barrier wells may not be required at that location. During the planning phase, such natural barriers may be exploited to limit the number of barrier wells required for suitable isolation of a particular reservoir segment. Further, the gas-confining barrier or lateral barrier discussed herein may be a natural geologic barrier or may be provided hydraulically by barrier well operation. In any case, the term lateral, when used in reference to a barrier, may denote a barrier whose orientation is vertical or may denote a barrier of varying slope, configuration, and structure. The lateral boundaries, however, are defined to prevent excessive horizontal gas migration that would otherwise interfere with the efficient displacement of water by gas within the target region.
It should be understood that when discussing the displacement of water from an isolated region, complete displacement or removal of the entire water volume is not the objective. That is, the desired or achievable proportion of water displaced in any application may be determined by many factors, such as formation characteristics, economic factors, and regulatory requirements. The desired or achievable proportion of formation fluid displaced to surface using the present method may therefore vary between applications and implementations of the method.
In some embodiments, a substantial amount of the water that was initially resident in a water zone or aquifer will be removed. However, those skilled in the art will understand that, inasmuch as this process involves immiscible displacement within a porous medium, capillary effects and surface tension phenomena dictate that even with effective and efficient displacement methods, residual water will remain within pores of the reservoir. Further, the gas that is displacing the water will not achieve 100 percent volumetric sweep efficiency throughout the region. Thus, after the water removal operation has been completed, some residual water will remain in the reservoir. A portion of this water results from capillary effects and surface tension phenomena within the pores. In some cases, water that may still be producible by displacement may be left within the reservoir by choice. The specific volumes of water produced, and rates of gas fluid injected, will be determined on a case-by-case basis based on various economic, geologic, and operational factors that will be evident to those skilled in the art upon reading of the present description.
Within the context of the present disclosure, reference is made to bitumen, water, and gas zones or regions. It will be understood by those skilled in the art that this does not necessarily imply that the reservoir within a given fluid zone is saturated with any one particular fluid. For example, a bitumen zone will contain some water saturation distributed throughout the porous structure. In a virgin rich oil sand, the pores may be 80 percent saturated with bitumen and 20 percent saturated with connate water. As a further example, the reservoir comprising a gas zone or a water zone that overlies and is in hydraulic contact with a bitumen zone or oil sand may contain a relatively small bitumen saturation distributed throughout the porous medium.
Prior to any displacement operation, the nature and extent of the aquifer (including any associated outcrops or subcrops), is characterized to determine one or more appropriate target regions, and suitable injection and production well locations to isolate each such target region. Such zones may be isolated and water displaced sequentially or concurrently.
Hydraulic barriers are established using vertical and/or horizontal and/or directional fluid injection wells. Water or other fluid is injected into these barrier wells, and circulates to the water production well(s) present within the target region. This water injection/circulation creates a barrier to gas migration beyond the target region. The pressurized gas, thus confined, is therefore constrained to move downward as gas injection continues.
The wells used to establish and maintain the hydraulic barriers will typically be a combination of vertical and horizontal injection wells, although other orientations of directional well may be employed. Depending upon the geological environment and the desired service of the wells, the wells will be completed in accordance with principles and practices that are well known to those skilled in the art. In most cases, water will be a suitable injection fluid, and will be injected at rates which provide a reservoir pressure along the desired hydraulic barrier that is greater than the estimated gas pressure within the isolated region.
With this areal confinement of the injected gas thus achieved and sustained by hydraulic means (operation of the barrier wells), and with the suitable placement within the water zone or aquifer of a water production well or wells, water in the aquifer is displaced downward by the injected gas within this confined area and the water thus displaced downward is subsequently produced at a suitably placed and appropriately completed water production well or wells within the isolated target region.
The temporary and reversible isolation provided by appropriate water injection into the barrier wells obviates the need for material barriers, plugging substances, viscosifying fluids, emulsifying fluids, or other types of mobility control agent to establish the isolated zones, or to effect displacement of water.
The elements of the system are illustrated schematically in
As shown, one or more gas injection wells 40 are located within a target region, with water injection wells 50 (barrier wells) present along the target region boundaries as necessary. One or more water production wells 60, are located at or near the base or low point of the target region. Each of the wells, 40, 50, 60, may be either horizontally or vertically oriented, or otherwise directionally drilled or, where there is a multiplicity of such wells, a combination of horizontally and vertically or otherwise directionally oriented wells.
The subsequent description will, for purposes of simplicity, refer to the well elements in the singular, with the understanding that a multiplicity of vertical and/or horizontal and/or directional wells can be substituted for the singular instance.
Initially, the porous and permeable medium within the water zone or aquifer 10 may be fully or preponderantly saturated with water 11. For example, the porous medium of an independent or isolated aquifer may be saturated 100 percent with water. On the other hand, the porous medium of a water zone or aquifer that is located above and in hydraulic contact with an oil sand may be saturated for example 90 percent with water and 10 percent with immobile bitumen. In either case, the only mobile liquid at original conditions is the water. Removal of water from the water zone or aquifer 10 over some defined area is desired. For example, it may be desirable to remove sufficient water within a region above the bitumen zone or oil sand 20 so that, subsequent to the water removal phase, suitable in situ recovery techniques can be applied within the oil sand to effect the recovery of bitumen.
A gas injection well 40, is drilled and completed, or an existing well is adapted for this purpose. In the embodiment shown in the Figures, the gas injection well 40 is located with a natural non-porous boundary to the left in the schematic, and is completed at or near the top of the target region. As a non-condensing pressurized gas 41 is injected into the gas injection well 40, the gas 41 would generally tend to override the water and move outward at or near the top of the target region due to the density and viscosity difference between the gas 41 and water 11. Without lateral confinement, the gas 41 would continue to override the water 11 and would not facilitate an efficient downward displacement of the water 11.
To provide lateral confinement of the injected gas using exclusively hydraulic means, a water injection well 50 is drilled and completed, or an existing well is adapted for this purpose. Purely for illustrative purposes, the water injection well shown in the Figures is depicted as a horizontal well, although this need not be so. Water is injected into the target region at the water injection well 50 so that, in the vicinity of said water injection well, said injected water is at a pressure which exceeds the pressure of the approaching gas 41 so that a hydraulic barrier 80 is created which prevents the injected gas 41 from moving laterally (horizontally) beyond said hydraulic barrier.
In addition, a water production well 60 is drilled within the target region, and completed at or near the base of the target region, or an existing well is adapted for this purpose. A combination of aquifer water and injected water is produced by water production well 60. Thus, in addition to creating a hydraulic barrier 80 to impede the horizontal flow of gas, the water injection well 50 concurrently provides water 61, either directly or through displacement, to the water production well 60 and thereby mitigates the adverse effects of gas channeling or fingering or coning, as measured by producing gas/water ratio, on the ability of the water production well 60 to produce efficiently. It will be understood by those skilled in the art that the specific pressures and rates employed at the gas injection well 40, the water injection well 50 and the water production well 60, can be initially estimated from calculation-based techniques, such as simulation, and can be refined in the field, it being understood that the pressure in the reservoir or target region at or surrounding or in the vicinity of the water injection well should exceed the pressure in the approaching gas zone so as to create an effective hydraulic barrier.
Gas injection well 40 is located within the target region, typically within the upper or middle portion of the target region. While gas injection to the lower region of the target region is expected to be possible, such location may be less effective if the gas injection occurs in close proximity to the water production well. That is, given that gas production from the target region should be reduced for greatest efficiency, the gas injection wells will typically be located an appropriate distance from the barrier wells and from the production wells. In some systems, a single injection well may deliver injected gas to more than one target regions, or to more than one location within a single target region. Further, several gas injection wells may deliver injected gas within a single target region if it is deemed economical and efficient to do so.
With reference to the embodiment shown in
With respect to appropriate location of the wells, it should be noted that the hydraulic barrier generated by operation of the barrier wells 50, defines the boundaries of the target region in which displacement is achieved. Accordingly, the location of the barrier wells should be pre-determined based on the volume/area of the region to be isolated and displaced. Further, the spacing of the barrier wells should be determined such that a suitable hydraulic barrier can be generated at reasonable water injection rates. That is, a greater spacing between barrier wells may require greater injection rates to ensure that the integrity of the hydraulic barrier is maintained between adjacent wells.
The barrier wells 50 are operated at a pressure such that the pressure of the water within the target region in the vicinity of the water injection well is incrementally higher than the pressure of the approaching gas 41, that increment being of a magnitude sufficient to create a hydraulic flow barrier 80 such that the injected gas 41 cannot advance laterally beyond said barrier. The injected gas 41, when surrounded by the water injection barrier, will thus be forced to advance downward, displacing water downward and towards the water production well 60. Ultimately, should the operation continue, the water within this confined region will be substantially displaced and produced. Concurrently, the water production well 60 is operated at a production rate suitable to function as a hydraulic sink for both water displaced by the gas injection well 40 and water displaced by the water injection well 50, produces said volumes of displaced water, while preventing or minimizing gas channeling or fingering or coning at the water production well 60. This balance may be maintained by monitoring the producing gas/water ratio.
As shown in
This is further illustrated in plan view in the particular embodiment depicted in
As mentioned above, displacement of water from the isolated target region (along with injected water) is best accomplished by a locating the water production well within the confined region as defined by hydraulic barrier 80. Thus, in the embodiment depicted in
Failure to observe the abovementioned teaching with respect to positioning of the production wells within the confines of the hydraulically isolated region will result in a flow regime which fails to accomplish the dual objectives of generating a hydraulic barrier 80 to horizontal gas flow and concurrently permitting the water production well 60 to remove water from the target region or aquifer 10 while mitigating gas channeling or fingering or coning, as measured by producing gas/water ratio, as the injected gas 41 advances and displaces the water downward.
It should be noted for completeness that, depending upon circumstances, such as those involving logistics or economics or environmental considerations, or combinations thereof, water that is produced from production wells that are located within a hydraulically constrained or confined region may be diverted or re-circulated, in whole or in part, so as to re-enter the target region at the water injection well or wells or, additionally, via other wells that may be completed within the reservoir or aquifer but which are located outside of or beyond the hydraulically confined region. Alternatively, a portion or all of the produced water may be diverted to locations that do not involve re-circulation into the target region from which said water was withdrawn.
Fluid Dynamics within the Barrier
The present system and method may be applied at depths involving not only high pressures but also relatively high pressure gradients to counteract the effects of density difference between gas and water, and the consequent ever-present tendency of the gas to override the water and move laterally outward in an unconfined manner. Thus, high pressures and relatively high pressure gradients would be required to manage the movement of the gas in the aquifer or target region so that a controlled volume of water is removed. Those same pressure gradients, in combination with the well configuration described herein, are important in mitigating the tendency of injected gas, with its very low viscosity, to channel or finger through the higher viscosity water and ultimately cone into the water production stream.
The system and method may also be applied at or near surface, in such applications as mine dewatering. Of course, surface applications may not require gas injection wells per se when the system is in contact with ambient air.
The application of conventional recharge/withdrawal well techniques based on single-phase flow source-sink theory is not valid in the present context. That is, injection of a gas phase, which is immiscible with the water and which is of significantly lower density, requires the application of non-linear flow concepts, in contrast to the linear flow concepts which form the basis of single-phase flow theory employed in conventional de-watering techniques. This non-linear characteristic of the flow or displacement regime is further exacerbated by the highly unfavorable viscosity contrast between the injected gas and the water which it displaces, which contrast promotes the tendency of the gas to channel non-uniformly through the water phase and into the water production well or wells.
The difficulty in achieving the desired control of the shape and confinement of the injected gas volume is embodied in the above-mentioned three aspects of the situation—immiscibility, density contrast and viscosity contrast, none of which exists when dealing with single-phase flow de-watering techniques, such as those conventionally extant in industry. As already noted, density and viscosity differences promote ongoing and undesirable override of the injected gas, and its continued horizontal spread, whereas the intended purpose of the injected gas is to ultimately displace the water downward so that it may be produced. However, to the extent that gas can be directed to displace the water downward, immiscibility of gas and water, combined with their very large viscosity contrast, promotes and exacerbates the tendency of gas to channel through the water that it was to have displaced and to ultimately channel or cone into, and interfere with production operations at, the water production well or wells. Thus, any wells employed to produce water from the target region as gas is being injected, or as the gas-water interface is advancing downward, will be generally vulnerable to gas coning, or other undesirable gas entry. Furthermore, coning theory determines that, unless the flux rates at the water production well are constrained to very low values, gas will tend to cone into a water producer. This gas coning tendency, if not otherwise ameliorated, will seriously compromise the ability of the water production well to remove practical volumes of water from the target region or aquifer.
A second and concurrent purpose of the water injection well or wells is to mitigate channeling or fingering or coning of gas into the water production well or wells, as evidenced by a reduction in produced gas/water ratio, as the gas-water interface migrates vertically downward over time, while allowing the water production well to operate at sufficiently high flow rates to permit a net withdrawal or removal of water from the confined region.
As noted above, when the methods described herein are practiced, gas flow is laterally constrained as a result of the hydraulic barrier or barriers created by the water injection well or wells. In accordance with the present teaching, the withdrawal of water required to effect the removal of natural water from the target region occurs through production wells that are located within this laterally constrained region. When this restriction is not observed, the desired flow regime described above will not be established, and efficient displacement of the target region will not be achieved.
The method and system described herein has been tested both by analytical equations, which describe the fluid regime associated with gas injection, water injection and water production and by rigorous mathematical modelling. Where the two approaches overlap, they demonstrate excellent agreement. More specifically, with hydraulic barriers created by the water injection wells so as to confine the lateral movement of injected gas, the positioning of the water production wells within the confines of these hydraulic barriers will result in efficient displacement. Without this limitation of the positioning of the water production wells, the efficiency and ultimate success of the operation may be compromised. Specifically, modelling has shown that alternate locations of the water production well will result in a fluid distribution in which the injected gas is not laterally constrained within the hydraulic barrier created by the water injection wells. That is, confinement of the gas is compromised and leads to ineffective water removal from the target region.
Reference to wells in the foregoing discussion, whether involving gas injection or water injection or water production, can imply that a well is oriented either substantially horizontally or substantially vertically, or it can possess some alternative directional trajectory. Thus, referring to vertical and horizontal wells by way of example, in one embodiment, the gas injection well may be substantially vertical. However, an array of vertical gas injection wells, or one or more horizontal gas injection wells could also be used. Similarly, water could be injected into a single substantially horizontal water injection well, or into more than one substantially horizontal water injection well, or into an arrangement of vertical wells so situated and so completed as to function in aggregate as an approximation of the horizontal water injection well or wells from a flow and pressure perspective. Analogously, the water producing function could be performed by a single substantially horizontal water production well, or by more than one substantially horizontal water production well, or by an arrangement of vertical wells so situated and so completed as to function in aggregate as an approximation of the horizontal water production well or wells from a flow perspective. Furthermore, within any one of these functions, a suitably designed mix of horizontal and vertical wells could be employed.
The foregoing description can be extended to include a multiplicity of lateral directions surrounding a gas injection well, or group of gas injection wells, so that a hydraulic constraint is created in each of these directions by a water injection well or wells, and so that an areally closed region is created, strictly by means of hydraulic constraints, throughout which water removal is occurring. However, in the event that the region of the aquifer from which water is to be removed or displaced is bound on one or more sides by natural constraints or boundaries, such as lithology (e.g., facies changes) or reservoir structure (e.g., pinch-out or fault), those particular sides may not require the creation of a hydraulic boundary in order to effect water removal. In that event, areal confinement may be achieved by a combination of natural boundaries and hydraulically imposed barriers.
Two basic methods of monitoring the integrity of the hydraulic barrier can be employed, either alternatively or together, during operation. One method involves monitoring conditions external to the hydraulic barrier and the second involves monitoring conditions within the hydraulically isolated region. Monitoring the conditions external to the barrier may involve the use of observation wells outside the barrier to detect the presence of gas, for example by sampling or logging or both. Within the hydraulically isolated region, the position of the gas/water contact can be monitored and, using mass balance calculations, can be compared against a calculated position of the contact to identify any discrepancies that would imply leakage outside the region.
As the water removal process within the aquifer is an evolving one, and is therefore dynamic, adjustments to the rates of gas injection, water injection and water production, and the associated pressures at these wells, may be required throughout the period of operation. Also, new wells may be added from time to time and existing wells shut in as required to maintain the conditions necessary to remove water from the aquifer, including the means of injecting water to sustain hydraulic barriers and the concurrent means, achieved by that same water injection operation, of inhibiting or mitigating gas channelling or fingering or coning at the water production wells. Suitable tactics to accommodate the dynamic nature of this process in a given situation, all while conforming to the present teachings, can be developed by one skilled in the art using two-phase immiscible displacement techniques.
With reference to
The series of depictions comprising
a depicts initial conditions, with no gas having yet been injected.
The above-described embodiments of the present invention are intended to be examples only. Alterations, modifications and variations may be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.
This application claims the benefit of and priority of U.S. Provisional Application No. 61/441,970 filed Feb. 11, 2011, entitled “Method for Displacement of Water from a Porous Formation” and Canadian Application No. ______ filed May 11, 2011.
| Number | Date | Country | |
|---|---|---|---|
| 61441970 | Feb 2011 | US |
