AXIALLY SEGMENTED DEPLETION OPERATIONS IN HORIZONTAL WELLS

Abstract

The present disclosure provides a method for improved production of hydrocarbons along the length of a horizontal well where non-uniform fluid chambers have formed in the reservoir. The present method distributes fluid along the length of a substantially horizontal wellbore that is located within a reservoir such that different recovery processes, or distinct phases of a given recovery process, operating proximally or adjacently within that same reservoir, and in hydraulic communication with each other within that reservoir, are managed concurrently along the single wellbore.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Patent Application No. 62/044,713 filed Sep. 2, 2014, which is incorporated herein by reference in its entirety.

FIELD

The present disclosure relates generally to thermal recovery processes in horizontal wells in subterranean reservoirs which exhibit non-uniform depletion of hydrocarbons along the length of the well. In particular, it is applicable in reservoirs containing viscous hydrocarbons such as bitumen or heavy oil.

BACKGROUND

Recovery of bitumen and heavy oil from reservoirs present significant challenges due to their high viscosities. Thermal recovery methods are generally used in order to reduce the viscosity of the hydrocarbons to mobilize them to flow to a production well. Examples of in situ thermal recovery methods include steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).

CSS uses a single well in its operation. Steam is injected into the hydrocarbon reservoir for a period of time, constituting the injection phase of a cycle. The well is shut in for a period of time as the steam soaks into the reservoir and heats the hydrocarbons to lower their viscosity and render them mobile. The well is then operated in a production phase, when the mobilized hydrocarbons move toward the well and are produced. When the rate at which hydrocarbons are produced falls below an economical level, the injection, soak, and production phases are repeated. CSS may be employed at vertical or horizontal wells.

SAGD uses a well pair consisting of two wells, one well for injection of steam and other fluids into the reservoir and a second well for production of hydrocarbons and other fluids from the reservoir. The wells are generally horizontal wells with the injection well positioned above and generally parallel to the production well. The injected steam rises from the horizontal injection well and permeates into the reservoir. A steam chamber forms in the hydrocarbon bearing zone which heats the reservoir. The viscous hydrocarbons become mobilized and drain downward under gravity to the production well. A reservoir will contain a number of SAGD well pairs. Although SAGD generally uses horizontal well pairs, it may also be performed using vertical or inclined well pairs.

SAGD includes a number of different phases in the process including start up, operation, and blowdown. CSS has similar phases in its process.

The SAGD start-up phase may employ one of several approaches. In the most commonly used approach, steam is circulated in both the injection and production wells to heat up the near wellbore region to create an initial steam chamber and establish communication between the injection and production well.

Once communication is established between the wells in the well pair, steam is no longer injected into the production well. The operational phase is initiated and steam is injected only into the injection well. As the steam chamber grows from the injection well, the hydrocarbons are heated and mobilized. They drain into the production well and will be produced, along with any condensate or other fluids present in the reservoir. Injection and production rates increase as the steam chamber grows towards the top of the reservoir. Once the steam chamber reaches the top of the reservoir, it begins to expand laterally within the reservoir. At this point, peak production rates are achieved.

Thermal efficiency of SAGD or CSS is measured by the steam-oil ratio (SOR). The SOR includes all measures of steam-oil ratio including the cumulative steam-oil ratio. The SOR is the ratio of volume of steam injected (expressed as cold water equivalent or CWE) to the volume of oil produced while the cSOR is the ratio of cumulative volume of steam injected (CWE) to the cumulative volume of oil produced. As the hydrocarbon content of the reservoir is produced and the remaining hydrocarbon content declines, the SOR will increase. The higher the SOR, the higher the steam usage. Accordingly, as the SOR increases, the process becomes less economical. At some point in the SAGD process, it may no longer be economical to continue steam injection and steam injection may be reduced or discontinued. The steam chamber is now largely depleted or “mature”.

Once SAGD is no longer economical and steam injection is discontinued, the blowdown phase is initiated. Typically during the blowdown phase, fluid such as a non-condensable gas is injected into the reservoir. This maintains the pressure in the steam chamber and allows production to continue without the injection of further steam. It also prevents the mature steam chamber from affecting SAGD in steam chambers at adjacent SAGD well pairs.

SAGD wells are conventionally 750 m to 1000 m in length. The reservoir along this length is generally not uniform. As a result, steam chambers that form along the length of a horizontal well may not form uniformly. This results in uneven steam chamber development and uneven hydrocarbon recovery along the length of a well pair. A steam chamber at one point in the well may form and produce efficiently while at another point, the steam chamber is slow to form as a result of the reservoir characteristics, wellbore characteristics, and other operational limitations. This results in inefficient recovery from the well since hydrocarbons at one point may not be fully recovered when hydrocarbons at another point along the length of the well are fully recovered. Continuing with steam injection along the entire length of the well under these circumstances will affect overall production efficiency and cost. Accordingly, when this uneconomic situation is encountered, current practice involves terminating operations at the affected well, or well pair, even though this may entail leaving significant unrecovered amounts of otherwise recoverable hydrocarbons.

Several methods have been attempted to allow for the uniform distribution of fluid along the length of a wellbore even where the associated reservoir has non-uniform characteristics.

WO2008/092241 is directed to a method for providing a preferential injection distribution from a horizontal injection well. In this method, the injection tubing string in the well bore has ports with selected distribution and geometry. This geometry is selectively controlled along the length of the tubing string to provide for selected flow restriction characteristics along the annulus in the wellbore so that when injection fluid is pumped into the tubing, a resulting flow resistance network is formed from the tubing bore, ports, annulus and formation. This results in a desired distribution of the fluid into the formation.

U.S. Patent Publication 2013/0213652 is directed to configurations of horizontal injection and production wellbores which are intended to maximize steam chamber growth, and production of hydrocarbons from the production well after an optional startup period. The reference uses flow distribution control devices and limited vertical spacing separating the wells.

“The Impact of Steam Placement Control on SAGD Performance: A Numerical Study from the Orinoco Heavy Oil Belt”, March 2008, World Heavy Oil Congress, Edmonton by Perdomo and Damas describes simulation studies of a field pilot design. The authors conclude that by incorporating inflow control devices in the completion, it was possible to achieve a better distribution of the steam chamber in the reservoir.

In each of these references, fluid injection into the well is controlled or altered along the length of the well. However, the same fluid is injected along the length of the well. Further, the same process, or phase of a process, is carried out along the length of the well.

Canadian Patent Application 2,678,348 is directed to a method of reducing fluid loss from operating chambers in SAGD to increase hydrocarbon recovery. This application describes selecting a mature SAGD steam chamber in one well pair and an adjoining operating SAGD steam chamber in an adjoining well pair. The mature steam chamber is depleted of hydrocarbons while the operating SAGD steam chamber is undergoing SAGD. These steam chambers have developed along well pairs in adjacent sections of the reservoir but with a buffer zone between them. An oxygen comprising gas is injected into the mature steam chamber or at a boundary or within a buffer zone between the mature steam chamber and the operating steam chambers for maintaining pressure within the mature chamber so as to reduce or avoid fluid leaking or cross flow from the operating chamber into the mature chamber. This process contemplates operating adjacent but separate well pairs at different stages of recovery in a different manner so as to reduce fluid leaking between them and affecting hydrocarbon recovery. However, it does not contemplate operating a single well system in such a manner as to address non-uniform steam chamber development to improve hydrocarbon recovery from a single well system.

These prior systems focus on wellbore configurations and flow control devices that will cause or encourage uniform flow, or a selected flow profile, along the length of the injection and/or production wellbores.

There is therefore a need to produce hydrocarbons from a length of a single horizontal well system, whether consisting of a single well or well pair, where steam chamber formation and hydrocarbon recovery is non-uniform along the length of the well system, and where various sections of the wellbore, as defined by these non-uniformities, may be at different operating stages.

SUMMARY

It is an object of the present disclosure to obviate or mitigate at least one disadvantage of previous hydrocarbon recovery methods.

In a first aspect, the present disclosure provides a method for recovery of hydrocarbons from a subterranean reservoir, where the reservoir has a well operating a recovery process. The method may include operating the recovery process in the well, including injecting a mobilizing fluid into the reservoir and producing mobilized hydrocarbons from the reservoir. The production of mobilized hydrocarbons may form at least two fluid chambers in the reservoir axially along the length of the well. The term “chambers” in this context refers to regions within the reservoir along the length of the wellbore which are distinguished by the difference in degree to which depletion has occurred among them. The production of mobilized hydrocarbons from the reservoir may be non-uniform causing the at least two fluid chambers in the reservoir to be non-uniform. The method may include assessing parameters indicative of the hydrocarbon recovery in the reservoir to allow for the segmentation of the well into distinct segments axially along the length of the well. Each segment may be associated with one of the at least two fluid chambers. The method may include segmenting the well into at least two segments. Each segment of the well may communicate with at least one of the fluid chambers formed in the reservoir wherein the fluid chamber in each segment is in fluid communication with the fluid chamber in at least one other segment. The method may include operating the at least two segments independently, at substantially similar pressures, for improving the hydrocarbon recovery as compared to a well where the same recovery process is carried out along the length of the well.

In a further embodiment, the present disclosure provides a method for recovery of hydrocarbons from a subterranean reservoir, where the reservoir has a well pair, comprising an injection well and a production well. The well pair operates a gravity drainage recovery process. The method may include operating the gravity drainage recovery process in the well pair, including injecting a mobilizing fluid into the reservoir through the injection well and producing mobilized hydrocarbons from the reservoir through the production well.

The production of mobilized hydrocarbons may form at least two fluid chambers in the reservoir axially along the length of the well. The production of mobilized hydrocarbons from the reservoir may be non-uniform, causing the at least two fluid chambers in the reservoir to be non-uniform. The method may include assessing parameters indicative of the hydrocarbons recovery in the reservoir to allow for the segmentation of the well into distinct segments axially along the length of the well. Each segment may be associated with one of the at least two fluid chambers. The method may include segmenting the well into at least two segments, each segment of the well communicating with one of the at least two fluid chambers formed in the reservoir, wherein the fluid chamber in each segment is in fluid communication with the fluid chamber in at least one other segment. The method may include operating the at least two segments independently, at substantially similar pressures, for improving hydrocarbon recovery as compared to a well pair where the same recovery process is carried out along the length of the well.

In further aspect, the step of operating the at least two segments independently includes injecting a first mobilizing fluid into one segment and injecting a second, different mobilizing fluid, or no mobilizing fluid, into the other segment. The first mobilizing fluid may be steam injected into the segment with less hydrocarbon recovery and the second mobilizing fluid may be a non-condensing gas injected into the segment with more hydrocarbon recovery. The recovery process may be steam assisted gravity drainage.

Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures.

FIG. 1 is a section view of a well pair configuration segmenting the well into independently operated segments.

FIGS. 2 to 4 are simulated reservoir profiles showing a well pair with steam chambers along their length, segments or portions of which are at different stages of SAGD recovery.

FIGS. 5 to 7 are graphs showing steam injection, hydrocarbon recovery, cSOR and recovery factor (RF) for simulated SAGD recovery methods.

FIGS. 8 and 9 are simulated reservoir profiles showing a well pair with steam chambers along their length at different stages of recovery using a method as set out herein.

FIG. 10 is a graph showing steam injection, hydrocarbon recovery, cSOR and RF for a simulated recovery method as set out herein.

DETAILED DESCRIPTION

Generally, the present disclosure provides a method for efficient hydrocarbon recovery within a reservoir and along a length of a horizontal well. The present method allows for improved production of hydrocarbons along the length of the well where non-uniform chambers have formed in the reservoir.

The present method distributes fluid along the length of a substantially horizontal wellbore that is located within a reservoir such that different recovery processes, or distinct phases of a given recovery process, operating proximally or adjacently within that same reservoir, and in hydraulic communication, directly or indirectly, with each other within that reservoir, are managed concurrently along the single wellbore.

The method is initiated after operation of an in situ recovery process within the reservoir which results in the formation of non-uniform fluid chambers in the reservoir. The fluid chambers represent hydrocarbon voidages in the reservoir where hydrocarbons have been recovered from the reservoir as a result of the in situ recovery process. The non-uniformity of the fluid chambers reflects non-uniform hydrocarbon recovery from the reservoir, a difference in degree to which depletion has occurred among them. The non-uniform (distinct) fluid chambers may be separate fluid chambers formed along the length of the well or they may be a single fluid chamber with varying sizes at different points along the length of the well. The reference to “distinct” fluid chambers or “at least two” fluid chambers includes fluid chambers created as separate fluid chambers not initially in communication with another fluid chamber, and a single fluid chamber formed with varying sizes along the length of the well where different sized chambers along the length of the well are in fluid communication or contact with one or more different sized fluid chambers along the length of the well. In both cases, distinct fluid chambers are identifiable along the length of the well.

The method includes creating a conformance profile using parameters along the length of a well which is indicative of hydrocarbon voidage and fluid chamber formation. The method includes assessing the profile to determine subdivision of the well into distinct axial regions or segments for the purposes of subsequent well operation and hydrocarbon recovery. Each segment may comprise a distinct fluid chamber and may be in fluid communication with a distinct fluid chamber in at least one other segment. It is not possible to see conformance along the length of the well so it is inferred from field and well data. This field and well data is commonly used by engineers in the field and includes but is not limited to, for example, time lapse (4D) seismic data which provides a view of heating within the reservoir as indicated by alterations, as compared with pre-operating base cases, to the geophysical properties of the reservoir as a consequence of the heating; knowledge of the geology along the well, commonly obtained from logs that are run in the well before the well is placed in operation; knowledge of the geology more broadly within the reservoir obtained, for example, from vertical strat wells drilled through the reservoir at various locations throughout the operating area; downhole pressure data, such as that obtained through the use of a bubble tube installed in the well; temperatures measured from temperature observation wells; surface heave, which measures the displacement of the earth at the surface as a consequence of the pressures and temperatures in the reservoir associated with thermal operations; and simulations which can yield estimates of conformance when used to history match or approximate observed well performance.

The method includes segmenting the wellbore into two or more operationally independent segments. The wells are segmented by retooling the well, or effectively isolating each segment within the length of the well. This may be done, for example, by running in packers or other equipment into the wellbore to isolate the segments, and using flow control devices in each segment to control the injection of fluid into the reservoir and the production of fluid from the reservoir into the wellbore. The fluid chamber associated with each segment is adjacent to and in hydraulic communication within the reservoir with an operationally distinct fluid chamber in another segment of the well.

Hydraulic communication between two reservoir fluid chambers implies that there is a sufficiently transmissible reservoir path between them to allow, under a pressure gradient or pressure difference between the chambers associated with practical operating conditions, discernable flow between chambers. Discernable flow implies that the presence of flow between chambers is measurable for example via monitoring of pressures in the two wellbore segments or via detection of fluids which have migrated between chambers, or both.

The segments are operated independently, i.e. each segment of the well may be operated as a separate well, even though adjacent wellbore segments are in hydraulic communication via the reservoir. The segments may be maintained at pressure levels that are equivalent or similar pressure levels, or at desired pressure levels for optimum hydrocarbon recovery and/or operation of the well. These pressure levels substantially maintain the injected fluid in each fluid chamber in the reservoir and do not allow the injection of a fluid in one chamber to adversely affect the injection of another fluid in an adjoining chamber. Similarly, production may occur from each segment but in such a manner that the reservoir process associated with one segment is not adversely affected by operations in the adjacent segment.

“Independent” as used herein means that the two or more well segments can be operated in a manner tantamount to operating two or more separate wells, even though the wellbore segments are in hydraulic communication within the reservoir. For example, if the reservoir initially undergoes SAGD prior to segmentation, then after segmentation, SAGD may be continued in one segment while simultaneously in another segment, injecting a non-condensable gas into a mature segment of the reservoir. When the wells are segmented, the injection of the non-condensable gas is carried out so that it does not adversely affect the SAGD process being carried out in the adjoining steam chamber, even though the chambers are in mutual fluid communication.

The method includes maintaining the pressure levels in each of the two or more wellbore segments at equivalent or similar pressure levels. A “similar” pressure level implies that the pressure in one segment is close to but not exactly identical to the pressure in an adjacent segment, the two segments being in mutual hydraulic communication. The pressure levels are not identical since a slight pressure difference may be beneficial to the recovery process.

The present method is carried out in horizontal wells. A horizontal well includes a well that is horizontal or substantially horizontal. The entire length of the well does not need to be horizontal and portions of it may deviate from horizontality.

In one example of the present method, SAGD is operated in a well pair until the formation of two non-uniform steam chambers is detected along the axial length of the well pair, such that one chamber is highly swept, with a higher percentage recovery (i.e. recovery efficiency) of hydrocarbons (“mature chamber”) and with an associated steam-oil ratio which indicates that the chamber has reached its economic limit, while the other chamber exhibits lower sweep efficiency and a higher percentage of unrecovered hydrocarbons (“operational chamber”). In the present method, the well may be segmented into two segments, one associated with each steam chamber. SAGD would be continued in the operational segment where a larger amount of unrecovered hydrocarbons are present. At the same time, a non-condensable gas would be injected into the segment with the mature chamber since fewer hydrocarbons will be recovered and continuing the injection of steam is not economical. The operational phase associated with the mature steam chamber in this example, which involves injection of a non-condensing gas, is also called “blowdown”. In operating each segment according to this example, a slight pressure difference between the operational chamber segment in which SAGD steam based recovery is occurring and the mature chamber segment in which blowdown is occurring may be imposed so as to favour flow towards the blowdown segment. This slight pressure difference is sufficient 1) to ensure that the migration of steam from the operational SAGD steam based recovery segment does not materially increase overall the steam-oil ratio (SOR) and 2) that migration of gases from the mature segment undergoing blowdown to the operational SAGD steam based recovery segment is prevented or impeded to an extent that any gases from the blowdown segment which might otherwise migrate to the operational segment are swept from the operational segment to the blowdown segment as a result of the slight pressure difference and therefore do not adversely affect hydrocarbon production rates in the operational segment.

Similarly, production rates from each segment are operated independently and may differ in each segment. Production rates are operated to maintain the appropriate pressure levels, as required.

When either an injection well or a production well is segmented, the segmentation may include the use of flow control devices to govern the injection or production rates in each segment.

The method is described above as a segmented case, where one segment of the reservoir is undergoing steam-based recovery operations and the other segment of the reservoir is undergoing recovery operations under blowdown. However, the method applies to wells where the segments include a gradation between these two types of operation. Thus, in some circumstances, such as at an earlier stage of the recovery process, the well may be segmented such that steam-based operations are continued in the reservoir associated with one segment while a mixed steam/non-condensing gas operation may be operating in the reservoir associated with the another segment.

Further, in maintaining the pressure levels at optimum levels, the method may also include limiting the injection rates by injecting into a segment at a zero rate, i.e. ceasing injection into one segment, or even injecting into a segment at a negative rate, i.e. withdrawing gas, to reduce the relative pressure. Similarly, the production rates are also limited to manage the pressures in the segments. Therefore, the production rates may also have a zero withdrawal rate if required.

The present method is useful with thermal recovery processes in bitumen and heavy oil reservoirs. These processes form fluid chambers in the reservoir. One example is SAGD where the injection of steam from an injection well forms steam chambers in the reservoir while producing mobilized hydrocarbons from a production well. The thermal operations contemplated also include other mobilizing fluids as well as the injection of an additive or other hydrocarbon with steam. For example, solvent may be injected as an adjunct or aid to steam, such processes being referred to by several different names including Solvent Aided Process (SAP) or solvent aided SAGD. The process also includes the injection of non-condensable gas into a mature fluid chamber. The non-condensable gas may be any known gas used in blowdown including natural gas, methane or other light hydrocarbons or may be an oxygen containing gas useful for example for in situ combustion. The present method is also useful in CSS processes wherein injection and production occurs in the same well.

FIG. 1 sets out one example of the present method. This figure shows a

SAGD well pair having an injection well 1 and a production well 3. In this example, the operation of SAGD in a reservoir created non-uniform steam chambers with uneven hydrocarbon production. The distal portion of the wellbore, associated with the toe of the well, has received inadequate steam and still contains substantial unrecovered oil. The proximal portion of the wellbore, associated with the heel of the well, has undergone effective depletion of hydrocarbons and is now ready for blowdown. “Blowdown” refers to the cessation of steam injection and the inception of non-condensing gas injection so that additional oil can be recovered at a viable productivity level due to high temperatures which are a holdover of the SAGD phase, combined with pressure maintenance by the gas without the need for additional steam. In the method exemplified in this figure, the wellbore is segmented into two segments and the reservoir associated with each wellbore segment is at a different stage of depletion.

The well is re-completed for segmented injection and production, i.e. for blowdown of the heel segment and for SAGD operation at the toe segment. Packers 5, 6 or other known devices are used in both the injection well 1 and the production well 3 to isolate each segment within the wellbore. Flow control devices are used to control the flow of fluid, whether steam or non-condensable gas, injected into the reservoir as well as production of hydrocarbons from the reservoir. Packers 5 isolate the heel segment of the injection well from the toe segment of the injection well so that steam is injected only at the toe segment and non-condensable gas is injected only at the heel end of the injection well. Packers 6 segment the production well. FIG. 1 shows inflow control devices 7 (ICD's) in the production well to limit production from the heel/blowdown segment relative to the toe/operational SAGD steaming segment.

While FIG. 1 shows a well pair, the present method may be carried out in a single well rather than a well pair. The well would be segmented according to the fluid/steam chamber formation and injection and production would be carried out within the single well. As well, FIG. 1 shows only two segments but the well may be segmented into multiple segments along its length. The wells in FIG. 1 include a liner 9 but the wells may be completed in any known manner.

Simulation Study

Simulations were carried out for a two segment SAGD well pair. The simulations are based on the reservoir characteristics at Foster Creek. The parameters for the simulation include:

SAGD wells—800 m long with 100 m spacing

30 m thick homogenous reservoir model

Permeability 6D,

Oil Saturation 80%

Porosity 33%

A base case was simulated to establish the steam chamber formation and hydrocarbon recovery within the reservoir when conventional SAGD is carried out for 20 years. FIGS. 2 to 4 show the steam chamber formation for the base case at 6 years, 10 years and 20 years. As can be seen, two steam chambers form along the length of the well but these do not form uniformly and the hydrocarbon recovery from each is not uniform. At 6 years of SAGD recovery, the heel portion of the well is highly swept with high recovery of hydrocarbons while the toe end of the well contains a larger amount of unrecovered hydrocarbons. By 10 years, the hydrocarbon remaining at the heel end is minimal while there is still significant hydrocarbon remaining to be recovered at the toe end of the well. Even at 20 years of SAGD, a pocket of unrecovered hydrocarbons still remain in the well near the toe end of the well. This chamber is not fully swept.

FIG. 5 is a graph for the base case setting out the steam injection, hydrocarbon recovery, cSOR and recovery factor (RF) as a function of time. The left hand axis indicates the steam injection and oil production rates in m3/day and also, when divided by ten, provides the scale for steam-oil ratio. The bottom axis reflects days of SAGD operation. The right hand axis references recovery factor. The graph shows that, at the end of 20 years, the cSOR is 3.5 while the recovery factor or recovery efficiency is 70% so that 70% of the hydrocarbons have been recovered.

FIG. 6 is a graph showing steam injection, hydrocarbon recovery, cSOR and RF, where SAGD is operated in the well pair for 6 years and blowdown is then initiated along the full length of the well. In this example, the well still has an incomplete sweep at 20 years. The cSOR is 2.1 but the recovery factor is only 61%.

FIG. 7 is a graph showing steam injection, hydrocarbon recovery, cSOR and RF, where SAGD is operated in the well pair for 10 years and blowdown is then initiated along the full length of the well. In this example, the sweep is improved but still incomplete and a portion of the hydrocarbons remains unrecovered. The cSOR is improved at 2.6 and the recovery factor is 67%.

FIGS. 8 and 9 show the formation of the steam chambers along the well pair when the present method is initiated. In this example, SAGD is operated in the well pair for 6 years. At this point, the well is segmented. Blowdown is initiated in the heel end of the well while SAGD is continued at the toe end of the well. FIG. 8 shows the steam chamber formation at 9 years. At 9 years, the steam chamber at the toe end of the well is highly swept. SAGD ceases at the toe end of the well and blowdown occurs at both the toe and heel end of the well. FIG. 9 shows the steam chamber development at 20 years. In this simulation, the well is near completely swept. There are no longer large unrecovered pockets of hydrocarbons, as seen in the base case examples. FIG. 10 is a graph showing steam injection, hydrocarbon recovery, cSOR and RF for this example. The cSOR is 2.2 and the recovery factor is 75%. These are improved over each of the three earlier examples, where SAGD only, or SAGD and blowdown after the initial period of SAGD, were operated in and along the entire length of the well pairs. The cSOR was lowered and the recovery factor was increased. The result is a more economical recovery of hydrocarbons from the reservoir.

The simulations show that the present method is effective to optimize hydrocarbon recovery and SOR for mature well pairs with long term poor conformance issues. It allows for the independent operation of well segments where mature segments with highly swept regions are operated on blowdown to limit steam consumption while operational segments with low sweep are operated with steam injection SAGD processes. It also promotes the sweep of gas away from the operational, unswept sections. The present method also has the potential to maximize the recovery of hydrocarbons while significantly reducing the SOR and cSOR. It allows an operator to target specific sections of specific well pairs within a pad to increase efficiency in its hydrocarbon recovery.

In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments. However, it will be apparent to one skilled in the art that these specific details are not required. The above-described embodiments are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope, which is defined solely by the claims appended hereto.

Claims

1. A method for recovery of hydrocarbons from a subterranean reservoir, where the reservoir has a well operating a recovery process, the method comprising:

a. Operating the recovery process in the well, including injecting a mobilizing fluid into the reservoir and producing mobilized hydrocarbons from the reservoir, wherein the producing mobilized hydrocarbons forms at least two fluid chambers in the reservoir axially along the length of the well, and wherein the producing mobilized hydrocarbons from the reservoir is non-uniform causing the at least two fluid chambers in the reservoir to be non-uniform;

b. Assessing parameters indicative of the hydrocarbon recovery in the reservoir to allow for the segmentation of the well into distinct segments axially along the length of the well, where each segment is associated with one of the at least two fluid chambers;

c. Segmenting the well into at least two segments, each segment of the well communicating with at least one of the fluid chambers formed in the reservoir, wherein the fluid chamber in each segment is in fluid communication with the fluid chamber in at least one other segment;

d. Operating the at least two segments independently, at substantially similar pressures, for improving the hydrocarbon recovery as compared to a well where the same recovery process is carried out along the length of the well.

2. The method of claim 1 wherein operating the at least two segments independently comprises:

a. injecting a first mobilizing fluid into a first of the at least two segments and injecting a second mobilizing fluid into a second of the at least two segments; or

b. injecting a first mobilizing fluid into a first of the at least two segments and injecting no mobilizing fluid into a second of the at least two segments; or

c. concurrently producing mobilized hydrocarbons from the at least two segments; or

d. producing hydrocarbons from a first of the at least two segments and producing no mobilized hydrocarbons from a second of the at least two segments; or

e. injecting a first mobilizing fluid into a first of the at least two segments and withdrawing or producing fluids from a second of the at least two segments;

to maintain desired pressures in each of the fluid chambers of the at least two segments.

3. The method of claim 1 wherein operating each segment independently comprises operating each segment at a pressure that is identical or substantially identical to the pressure in an adjacent segment.

4. The method of claim 1 wherein a first of the at least two segments has less hydrocarbon recovery than a second of the at least two segments and wherein operating the at least two segments independently comprising injecting steam into the first of the at least two segments and injecting non-condensable gas into the second of the at least two segments.

5. The method of claim 1 wherein segmenting the well comprises positioning flow control devices to isolate sections of the well and limit fluid flow from the well into the reservoir and/or limit fluid flow from the reservoir into the well.

6. The method of claim 1 wherein the mobilizing fluid comprises one or more of steam, hydrocarbon solvents, surfactants, and non-condensing gas.

7. The method claim 6 wherein the non-condensing gas comprises a light hydrocarbon or oxygen comprising gas.

8. The method of claim 1 wherein the parameters indicative of the hydrocarbon recovery comprises temperature, seismic data, geology of the reservoir, geology of the wellbore, pressures, surface heave, and simulations based on one or more of the parameters.

9. The method of claim 1 wherein the recovery process is a gravity dominated process or a cyclic process.

10. The method of claim 1 wherein the gravity dominated process is steam assisted gravity drainage (SAGD).

11. A method for recovery of hydrocarbons from a subterranean reservoir, where the reservoir has a well pair, comprising an injection well and a production well, the well pair operating a gravity drainage recovery process, the method comprising:

a. Operating the gravity drainage recovery process in the well pair, including injecting a mobilizing fluid into the reservoir through the injection well and producing mobilized hydrocarbons from the reservoir through the production well, wherein the producing mobilized hydrocarbons forms at least two fluid chambers in the reservoir axially along the length of the well, and wherein the producing mobilized hydrocarbons from the reservoir is non-uniform, causing the at least two fluid chambers in the reservoir to be non-uniform;

b. Assessing parameters indicative of the hydrocarbons recovery in the reservoir to allow for the segmentation of the well into distinct segments axially along the length of the well, where each segment is associated with one of the at least two fluid chambers;

c. Segmenting the well into at least two segments, each segment of the well communicating with one of the at least two fluid chambers formed in the reservoir wherein the fluid chamber in each segment is in fluid communication with the fluid chamber in at least one other segment, and

d. Operating the at least two segments independently, at substantially similar pressures, for improving hydrocarbon recovery as compared to a well pair where the same recovery process is carried out along the length of the well.

12. The method of claim 11 wherein operating the at least two segments independently comprises:

a. injecting a first mobilizing fluid into a first of the at least two segments and injecting a second mobilizing fluid into a second of the at least two segments; or

b. injecting a first mobilizing fluid into a first of the at least two segments and injecting no mobilizing fluid into a second of the at least two segments; or

c. concurrently producing mobilized hydrocarbons from the at least two segments; or

d. producing hydrocarbons from a first of the at least two segments and producing no mobilized hydrocarbons from the second of the at least two segments; or

e. injecting a first mobilizing fluid into a first of the at least two segments and withdrawing or producing fluids from a second of the at least two segments, to maintain desired pressures in each of the fluid chambers of the at least two segments.

13. The method of claim 11 wherein operating each segment independently comprises operating each segment at a pressure that is identical or substantially identical to the pressure in an adjacent segment.

14. The method of claim 11 wherein a first of the at least two segments has less hydrocarbon recovery than a second of the at least two segments and wherein operating the at least two segments independently comprising injecting steam into the first of the at least two segments and injecting non-condensable gas into the second of the at least two segments.

15. The method of claim 11 wherein operating each segment comprises injecting into one segment a mixture of steam and non-condensable gases.

16. The method of claim 11 wherein segmenting the well comprises positioning flow control devices to isolate sections of the well and limit fluid flow from the injection well into the reservoir and/or limit fluid flow from the reservoir into the production well.

17. The method of claim 11 wherein the parameters indicative of the hydrocarbon recovery comprises temperature, seismic data, geology of the reservoir, geology of the wellbore, pressures, surface heave, and simulations based on one or more of the parameters.

18. The method of claim 11 wherein the mobilizing fluid comprises one or more of steam, hydrocarbon solvents, surfactants, and non-condensing gas.

19. The method claim 18 wherein the non-condensing gas comprises a light hydrocarbon or oxygen comprising gas.

20. The method of claim 11 wherein the gravity dominated process is steam assisted gravity drainage (SAGD).