CN106934200B

CN106934200B - Estimation of recovery coefficients in foam-driven hydrocarbon reservoirs

Info

Publication number: CN106934200B
Application number: CN201511030435.1A
Authority: CN
Inventors: 王香增; 王书宝; 高瑞民; 杨永超; 曾凡华; 杨珺; 张艺钟
Original assignee: Individual
Current assignee: Individual
Priority date: 2015-12-31
Filing date: 2015-12-31
Publication date: 2020-04-24
Anticipated expiration: 2035-12-31
Also published as: CN106934200A

Abstract

A novel estimation method for recovery coefficients in foam-driven hydrocarbon reservoirs. The method divides the reservoir into three swept sub-zones and estimates the sweep efficiency and the displacement efficiency of each zone. From the sweep efficiency and the displacement efficiency, the oil recovery factor is determined as a function of the injection pore volume. This method provides more accurate results, higher computational speed, and uses less input data than conventional numerical simulation methods.

Description

Estimation of recovery coefficients in foam-driven hydrocarbon reservoirs

Technical Field

The present invention relates to methods for recovering oil from a hydrocarbon reservoir, and more particularly to methods for estimating recovery coefficients using foam-driven enhanced oil recovery techniques in a reservoir sweep within a hydrocarbon reservoir.

Background

Conventional oil recovery methods cannot recover anywhere near the oil confined in the reservoir rock. Many types of enhanced oil recovery methods are used to increase production, including gas, liquid or steam driven reservoirs to extract residual oil. In the 1950 s, foam flooding was proposed as a displacement system to improve the oil recovery factor. Since the 1960 s, a large number of experiments and field tests are introduced, and the effectiveness of foam flooding in improving the oil recovery coefficient is verified, especially the effectiveness of the foam flooding on an inhomogeneous oil reservoir.

In reservoir flooding operations, surfactants are often used to help form emulsions between, for example, an aqueous drive solution and a hydrophobic oil, which can enhance the separation of the oil from the rock. Other gas or steam driven oil methods also typically use foam-forming surfactants, foam flooding being a method of increasing oil recovery in which foam is injected into the reservoir to increase the sweep efficiency of the flooding fluid. Foam can be generated in the reservoir cavity or at the surface prior to injection. Foam flooding mitigates sweep non-uniformities, such as those caused by layers having higher permeability than the surrounding formation or those caused by gravity overburden.

The foam is prepared by adding at least one blowing agent to a gas (such as air, nitrogen, CO)₂Etc.) into the liquid phase. In the oil industry, the gas used to generate the foam is selected from air, nitrogen, CO₂Or natural gas, the liquid used to produce the foam is primarily water, such as fresh water, formation water, or brine.

Foam flooding has also been proposed as an effective method for producing tight reservoirs with very low permeability. One problem involved in recovering oil from reservoirs of these nature is the estimation of the recovery factor. Enhanced modeling or calculation of recovery coefficients from such drive reservoirs is believed to be certainly acceptable.

Current modeling methods for estimating the recovery factor for oil recovery from a reservoir have two key limitations. These limitations include the actual speed at which the calculations are made and the accuracy of the model. From an accuracy standpoint, accurately estimating the recovery factor in a reservoir undergoing foam actuation is difficult because of the need to accurately estimate the sweep efficiency through the reservoir. As the permeability of the reservoir becomes lower, or the geology of the reservoir becomes more complex, it becomes more difficult to find a suitable single equation to reasonably accurately estimate the recovery factor in these situations. As such, from the perspective of more accurate modeling and the use of foam driven enhanced oil recovery techniques, an oil recovery factor modeling approach that overcomes some of these limitations or that can yield more accurate results than prior art approaches is considered more desirable.

One of the other limitations in current prior art methods is the computational power required to calculate the sweep efficiency and other variables needed to estimate the recovery factor. Developing a single large equation for achieving estimation of the oil recovery factor from a large number of data points, etc., from the formation of a hydrocarbon reservoir is another limitation of effectively using such modeling techniques in planning or implementing a foam flooding project. It is believed that this would certainly be acceptable if an improved method of estimating the recovery factor in a foam-driven hydrocarbon reservoir could be found that requires less computational power or results obtained more quickly than prior art methods.

Disclosure of Invention

The present invention, a method of estimating the recovery factor in a foam-driven reservoir, represents an improvement over the existing methods heretofore because it provides a more refined calculation method, resulting in a more accurate estimation of the recovery factor within the reservoir sweep of a hydrocarbon reservoir than is currently used.

The present invention, a method of estimating the recovery factor in a foam-driven reservoir, also represents an improvement over the methods of estimating the recovery factor in a reservoir that have heretofore been available because the results of the model can be more quickly calculated for each drive cycle prediction in a drive operation by subdividing the calculation and estimation into a plurality of swept sub-zones based on an understanding of the reservoir and drive parameters.

The object is achieved by a method for estimating the recovery factor in a foam-driven reservoir, comprising in a first step defining a reservoir sweep area as the area within the reservoir between at least one injection well and at least one production well, wherein gas and liquid surfactant injected into the at least one injection well during at least one drive cycle sweeps oil through the reservoir sweep area to the at least one production well for recovery therefrom. As described herein, the definition of a reservoir sweep area is understood by those skilled in the art of oil and gas geology and enhanced oil recovery drive engineering planning and implementation. From the point of view of the modeling methods described herein and in the larger scale planning of the drive project, the definition of the reservoir sweep and the location of at least one production well and at least one injection well are important initial considerations.

The oil recovery coefficient calculation method can be used for calculating the oil recovery coefficient in the oil-gas reservoir during each oil displacement cycle in the oil displacement operation. Each drive cycle is typically made up of: a stream of gas and the stream of surfactant fluid are injected into the geology or formation of the hydrocarbon reservoir. While the calculation and estimation method can be used to estimate a single shot or drive cycle, it is particularly expected that the method will be most applicable when calculating reservoir recovery factors for multiple drive cycles within a drive operation.

After the reservoir sweep is defined, the next step of the method, which is performed for some or all of the drive cycles in the drive operation, includes initially determining reservoir and drive parameters for the reservoir sweep based on the current state of gas and liquid surface active agents injected into the reservoir sweep. The reservoir and drive parameters can vary depending on, among other factors, the operator, the operation, or the geology of the reservoir. As described herein, various reservoir and drive parameters that will be used in certain embodiments of the method and in the calculations of the present invention will be apparent to those skilled in the art, all of which are included within the scope of the present invention.

The next step in the method of estimating the recovery factor in a foam driven reservoir of the present invention comprises subdividing the reservoir sweep area into three sweep sub-areas according to the reservoir and the drive parameters and the current state of the operation or modeled drive operation: a foam sweeping sub-zone, a water sweeping sub-zone and a gas sweeping sub-zone. The push sub-zones are redefined for each drive cycle because the shape and size of each push sub-zone can be dynamically varied according to different reservoir and drive parameters during the drive operation.

After defining three push-broom sub-areas, a calculation step is provided in which the following are calculated:

longitudinal and volumetric sweeping efficiencies within each sweeping sub-zone;

the total swept area of the reservoir swept area, which is the volumetric area of the reservoir swept area swept by the foam at the current drive cycle;

foam swept area, which is the volumetric area of the foam swept sub-area swept by the foam at the current drive cycle;

water swept area, which is the volumetric area of the water swept sub-zone swept by water at the current drive cycle;

gas swept area, which is the volumetric area of the gas swept sub-zone swept by the gas at the current drive cycle;

a foam-breakthrough area, which is the volumetric area of the foam-swept area penetrated by the existing foam within the flooding cycle, which includes the foam-swept area and its surrounding foam-bypass area due to the difference in mobility between the foam and the oil;

water breakthrough area, which is the volumetric area of the water swept sub-zone that is penetrated by existing water within the flooding cycle, which includes the water swept area and its surrounding water bypass area due to the difference in mobility between water and oil;

gas breakthrough area, which is the volumetric area of the gas swept area that is penetrated by the existing gas within the flooding cycle, which includes the gas swept area and its surrounding gas bypass area due to the difference in mobility between the gas and the oil; and

total penetration area, which is the sum of foam penetration area, water penetration area and gas penetration area.

The calculations provided in the calculation step may also depend on the reservoir and drive parameters, and those skilled in the art will appreciate that the specific calculations for each variable described for the calculation step can include using the reservoir and drive parameters or can be optimized in many ways to produce the most accurate results possible without departing from the intended scope of the invention.

After this calculation step is completed, the next step in the method described herein is the oil recovery coefficient estimation step, in which the contribution of the oil recovery coefficient in each push sub-zone is estimated using the variables determined in the calculation step. In particular, the oil recovery coefficient estimation step first comprises calculating a foam zone oil recovery coefficient, which is the oil recovery coefficient contributed by the foam swept sub-zone. Calculating the oil recovery coefficient of the water area, wherein the oil recovery coefficient is the oil recovery coefficient contributed by the water push-broom sub-area; and a gas zone oil recovery coefficient, which is the oil recovery coefficient contributed by the gas sweep sub-zone.

As in the case of the calculation step, it is also possible to use the reservoir and drive parameters in some calculations in the oil recovery coefficient estimation step, in some iterations of the method of the invention. The use of reservoir and drive parameters to optimize or perform the calculations and estimates at this step will also be understood by those skilled in the art and are also within the scope of the present invention.

And then selecting a calculation method of the total oil recovery coefficient according to the comparison of the total sweep area and the total penetration area. Depending on which of these calculations is the highest result, the appropriate calculation method for the total reservoir recovery factor is selected. After a suitable reservoir recovery factor calculation method is selected, the calculation can be performed.

If the total penetration area is less than the total push-broom area, then the selected sub-region based recovery coefficient calculation method may sum the foam zone recovery coefficient, the water zone recovery coefficient, and the gas zone recovery coefficient to obtain the reservoir recovery coefficient. Alternatively, if the total penetration area is greater than the total push-broom area, the calculation can include, for each of the three push-broom sub-areas:

1. calculating the maximum area push-broom efficiency;

2. calculating the heterogeneous push-broom efficiency after penetration;

3. calculating the area push-broom efficiency after penetration and the heterogeneous push-broom efficiency after penetration;

4. calculating the discharge efficiency; and

5. calculating a sub-region oil recovery factor for the sub-region using the displacement efficiency and the volume sweep efficiency corresponding to the sub-region.

The calculated sub-area recovery coefficients for all three swept sub-areas would then be summed in this case to obtain the reservoir recovery coefficient.

After the calculation of the reservoir recovery factor is completed, the calculated reservoir recovery factor can be stored, which in an extended embodiment of the method will be used to map a complete plot of the reservoir recovery factor calculated for all drive cycles in a drive operation on one axis of the plot.

The method of the invention can be used to determine the oil recovery factor for a single drive cycle or a drive operation consisting of a single drive cycle, or the method can be used to calculate the oil recovery factor for a reservoir being driven in a drive operation comprising a plurality of drive cycles. One skilled in the art will appreciate that such methods can be encompassed within the context and claims set forth herein based on the context.

The method of the invention can model the oil recovery coefficient for the displacement operations of the reservoir using any number of injection wells and any number of production wells.

The foam-driven reservoir recovery factor estimation method of the present invention can be performed manually or, more likely, in the form of computer software. The computer software method can use a computer software program built for a specific purpose, mathematical modeling software configured to perform the required calculations, or even a spreadsheet or similar method. Those skilled in the art of software design will recognize any number of different types of computer software methods, all of which are encompassed within the scope of the present invention.

The present invention, a non-transitory computer readable storage medium for estimating recovery factors in foam-driven hydrocarbon reservoirs, achieves its objects, comprising a computer readable storage medium containing instructions that when executed by a computer perform the functions of: a reservoir sweep is defined as the volumetric region within the reservoir between at least one injection well and at least one production well wherein gas and liquid surfactants injected into the at least one injection well during at least one drive cycle will push oil through the reservoir sweep to the at least one production well for production therefrom.

After defining a reservoir sweep area, the computer readable storage medium will cause the computer to determine, for each drive cycle, reservoir and drive parameters for the reservoir sweep area based on the current state of gas and liquid surfactants injected into the reservoir sweep area, and using the reservoir and drive parameters, subdivide the reservoir sweep area into three sweep sub-areas: a foam sweeping sub-zone, a water sweeping sub-zone and a gas sweeping sub-zone.

The computer readable storage medium will then cause the computer to, in the calculating step:

6. calculating the longitudinal push-broom efficiency and the volume push-broom efficiency in each push-broom sub-area;

7. calculating the total push-broom area of the oil deposit push-broom area, wherein the total push-broom area is the volume area of the oil deposit push-broom area pushed by foam in the current oil displacement cycle;

8. calculating a foam sweeping area which is the volume area of a foam sweeping sub-area swept by foam in the current flooding cycle;

9. calculating a water push-broom area, which is the volume area of a water push-broom sub-area that is pushed away by water during the current flooding cycle;

10. calculating a gas swept area, which is the volumetric area of the gas swept sub-area swept by the gas during the current drive cycle;

11. calculating a foam penetration area, which is the volumetric area of the foam swept sub-area penetrated by the existing foam within the flooding cycle, which includes the foam swept area and its surrounding foam bypass area due to the difference in mobility between the foam and the oil;

12. calculating a water breakthrough area, which is the volumetric area of the water swept sub-area within the flooding cycle that is penetrated by existing water, which includes the water swept area and its surrounding water bypass area due to the difference in mobility between water and oil; and

13. calculating a gas breakthrough area, which is the volumetric area of the gas swept area penetrated by the existing gas within the drive cycle, which includes the gas swept area and its surrounding gas bypass area due to the difference in mobility between the gas and the oil; and calculating a total penetration area that is the sum of the foam penetration area, the water penetration area, and the gas penetration area.

After the calculating step is completed, the computer readable storage medium then initiates or instructs the computer to perform a coefficient of oil recovery estimating step, comprising the steps of:

14. calculating an oil recovery coefficient of the foam area, wherein the oil recovery coefficient is an oil recovery coefficient contributed by the foam pushing and sweeping sub-area;

15. calculating the oil recovery coefficient of the water area, wherein the oil recovery coefficient is the oil recovery coefficient contributed by the water pushing and sweeping sub-area;

16. calculating the oil recovery coefficient of the gas area, wherein the oil recovery coefficient is the oil recovery coefficient contributed by the gas push-broom sub-area;

17. selecting an oil reservoir oil recovery coefficient calculation method to be used by comparing numerical values of the total sweep area and the total penetration area; and

18. performing the selected reservoir recovery factor calculation.

Variations of the calculations and methods performed by the computer readable storage medium will be any changes that can reasonably be inferred within the general scope of the oil recovery coefficient estimation method described herein.

An important advantage of using computer software to perform the method of the present invention is that in embodiments of the method comprising plotting one or more plots from calculated reservoir recovery factors, after the reservoir recovery factors for a desired drive cycle within a drive operation have been calculated, the plots can reasonably be directly plotted from purpose-built software or many available modeling tools. It is understood that the use of computer software to render these drawings for the remainder of the method according to the present invention is also within the scope of the present invention, whether the particular method employed involves the use of an integrated software tool and the remainder of the calculation of the present invention is the use of a user interface or printed report format to render one or more of the drawings of this information, or the use of a separate drawing tool installed on the stored reservoir recovery data.

Drawings

To facilitate a discussion of any particular element or act, the most important digit or digits in a reference number identify the reference number in which the element is first introduced.

FIG. 1 is a graph showing longitudinal sweep efficiency as a function of reservoir and drive parameters in accordance with one embodiment of the present invention;

FIG. 2 illustrates one embodiment of a total sweep area in a hydrocarbon reservoir to which the coefficient of recovery estimation model of the present invention can be described in comparison;

FIG. 3 is a flow chart showing steps in one embodiment of a method of estimating recovery coefficients for a foam-driven reservoir of the present invention;

FIG. 4 is a flow chart showing steps in another embodiment of the method of estimating recovery coefficients for a foam-driven reservoir of the present invention, including the step of using a reservoir recovery coefficient plot stored for a plurality of drive cycles;

FIG. 5 is a graph showing volumetric sweep efficiency as a function of reservoir and drive parameters in accordance with an embodiment of the present invention;

FIG. 6 is a graphical result of a coefficient of oil recovery estimation in accordance with the method of the present invention;

FIG. 7 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 8 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 9 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 10 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 11 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 12 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 13 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 14 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 15 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 16 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 17 is another plot of the estimation of the coefficient of oil recovery according to the method of the present invention;

FIG. 18 is a flow chart showing the steps of one embodiment of the method of the present invention performed by processor instructions on a computer readable storage medium;

fig. 19 is an exploded view of the steps of the drive cycle circuit of fig. 18.

Detailed Description

Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. Although any methods and materials similar or equivalent to those described herein can be used in the practice or testing of the present invention, the preferred methods and materials are now described.

As described herein, the present invention includes a novel method for estimating the recovery factor of a foam-driven reservoir. The method includes a number of steps, described in further detail below, that can accurately and timely predict the recovery factor in a foam flooding project in a hydrocarbon reservoir.

Foam flooding is a technique used to improve the recovery factor in oil and gas reservoirs. Foam flooding generally consists of the following operations: an injection well in a hydrocarbon reservoir is provided into which a stimulant for the reservoir can be injected, the stimulant being capable of pushing oil contained in the reservoir and rock formation toward a production well from which swept oil can be collected. Typically, a flooding operation consists of a series of flooding cycles in which gas and/or liquid surfactants are injected into injection wells to sweep or push oil through the formation into production wells.

Injection of gas and surfactant fluids into a formation typically results in the generation of foam in the formation. The foam is generated by mixing the injected liquid and gas together under an external pressure differential. In each flooding cycle of a flooding operation, a stream of liquid surfactant (e.g., water, brine, etc.) is injected, followed by a stream of free gas. Due to the former instability, the gas in the liquid surfactant will eventually separate. Gas and liquid surfactants are injected cyclically into the reservoir, whereby foam, water and gas will be present simultaneously in the reservoir. From the perspective of the prior art and a general understanding of the methods of the present invention, the injection of a single pair of a stream of liquid surfactant and/or a stream of free gas into a formation or reservoir via an injection well is referred to as a primary drive cycle.

It is often necessary to calculate or model possible recovery factors or hydrocarbons flushed from a reservoir prior to or during a drive operation. The method of estimating the recovery factor of a foam driven reservoir provided herein provides a method of modeling or calculating the likely recovery factor from a hydrocarbon reservoir based on the foam flooding technique used.

Typically, the production from a hydrocarbon reservoir in foam flooding applications and other enhanced oil recovery projects (such as those described herein) is measured by comparing the recovery factor of the reservoir or some portion thereof. The recovery factor is a measure of the production contrast or generally the reservoir productivity used to gauge the different enhanced oil recovery measurements. The enhancement of the production factor measurement, either by modeling or by certain production activities, is generally an indicator of the enhancement of the production of the reservoir. As such, oil and gas producers need to find ways to maximize the recovery factor in different applications in this type of application, and for this purpose, need to be able to model the recovery factor in different situations. The invention relates to an oil recovery coefficient estimation method of a foam-driven oil reservoir, in particular to a method for modeling an oil recovery coefficient under different foam flooding conditions and along with time in order to master and/or maximize the yield of a specific foam flooding project.

For purposes of the methods described herein, the area in which the foam flooding is performed and the foam-driven reservoir from which oil is recovered is referred to as the reservoir sweep area. The reservoir sweep area is the area within the reservoir between the injection well and the production well into which the injection gas and the liquid surfactant are to be injected during at least one drive cycle of a drive operation.

General method overview:

as noted above, the present invention comprises a foam-driven reservoir coefficient of oil recovery estimation method that can preferably be implemented in a computer software implementation for calculation (although manual implementation of the method itself is also novel and would fall within the scope of the present invention). With reference to fig. 3 and 4, we will now show a general overview of two embodiments of the method of the invention, and we will then provide a more detailed description and analysis of the modeling of certain sample data, demonstrating the utility of the invention.

Figure 3 is a flow chart showing the steps of one embodiment of the method of the present invention. As described elsewhere herein, the method of the present invention can be performed manually or in a traditional paper-based form, or more likely as a software system, particularly where there is a drive operation consisting of a large number of drive cycles. All such methods are within the scope of the present invention.

Referring to FIG. 3, the definition of a reservoir sweep is first shown at step 3-1. As noted above, the reservoir sweep area is the area within the reservoir that extends between at least one injection well to at least one production well into which a stream of gas or liquid surfactant is injected in order to sweep oil from the reservoir, and from which foam, gas, water or other liquid surfactant and oil combinations are collected and extracted by sweep and drive operations. Separating the recovered liquid into oil and other components is beyond the scope of the method of the present invention, but one skilled in the art would know how to separate the fluids collected from the reservoir by the zone flooding operation.

The flooding operation itself includes injecting a plurality of streams of gas and liquid surfactant (e.g., water, brine, etc.) into the formation of the reservoir through at least one injection well. Each pair of gas and liquid injection is called a flooding cycle. The entire drive operation will typically consist of multiple drive cycles, although it should be understood that the method of the present invention can be used to calculate the recovery factor of the reservoir sweep from as few as a single drive cycle up to any drive operation including as many as tens or even hundreds of drive cycles. Again, changes or extensions to the overall flooding operation and its impact on the mathematical function of the present method of estimating the flooding factor of a foam-driven reservoir are also within the scope of the present invention.

After defining the reservoir sweep area as shown in step 3-1, a series of calculations are performed for the various reservoirs and the drive parameters for the reservoir sweep area and for each drive cycle in the drive operation. One drive cycle is shown in steps 3-2 through 3-10 of FIG. 3. This means that for each drive cycle the drive cycle loop of the flowchart will be performed, and then the coefficient of recovery estimation method is performed on this basis.

The first step in the drive cycle loop 3-2 is to define reservoir and drive parameters 3-3. As described elsewhere herein, reservoir and drive parameters may include reservoir porosity, factors that facilitate penetration between different phases within the reservoir, and other parameters used for drive operations (e.g., including the volume of gas or liquid surfactant injected in a particular reservoir or drive cycle, etc.). The different types of reservoir and drive parameters that may be used in the performance of the method of the present invention will be known to those skilled in the art and are described herein, all of which are included within the scope of the present invention. The reservoir and drive parameters may vary from drive cycle to drive cycle or may remain constant.

After defining the reservoir and the drive parameters for a particular drive cycle, the reservoir sweep area will be subdivided into a plurality of sweep sub-areas, namely a foam sweep sub-area, a gas sweep sub-area, and a water sweep sub-area. The definition of these push sub-zones will be calculated or determined from knowledge of the reservoir and the drive parameters and the general state of the drive operation within the reservoir. Effectively, in a flooding operation, the foam sweep sub-zone, gas sweep sub-zone, and water sweep sub-zone will move the formation moving through the reservoir sweep zone from at least one injection well to at least one production well. The speed of movement, front shape and size of these swept sub-zones will all be affected by various reservoir and drive parameters, again, modeling of these swept sub-zones is provided within the scope of the invention, regardless of the particular method employed.

After subdividing the reservoir sweep area into these three sweep sub-areas, the next step in the method described in steps 3-5 is to calculate the longitudinal sweep efficiency and the volumetric sweep efficiency for each sweep sub-area. The details of these calculations are described elsewhere herein. In addition to the calculation of the longitudinal sweep efficiency and the volumetric sweep efficiency shown in steps 3-5, it is also shown in steps 3-6 that other calculations are performed that are needed to estimate the recovery factor contribution of each sweep sub-zone to the total reservoir recovery factor in a particular drive operation or drive cycle. There are some specific models that are considered most suitable for estimating the oil recovery coefficients of each swept sub-zone or their contribution to the oil recovery coefficient of the total reservoir. This shows that in step 3-7, after calculating the individual estimates of the recovery coefficients (foam zone recovery coefficient, gas zone recovery coefficient, and water zone recovery coefficient) for each sweep sub-zone, the total reservoir recovery coefficient can be determined. This is shown at step 3-8.

As detailed in the specification, a specific calculation method needs to be selected to determine the reservoir recovery factor, as shown in steps 3-8. The calculation method selected will be determined in large part from the calculated values of the permeability coefficient between the swept sub-zones in the reservoir sweep. After 3-8 a suitable reservoir recovery factor calculation method is selected, the calculation will be performed resulting in a calculated reservoir recovery factor. Finally, as shown in steps 3-9, the calculated reservoir recovery factor may be stored, and then the end of the drive cycle is shown in steps 3-10. The drive cycle loop may then be executed for other drive cycles in the drive operation until the maximum number of drive cycles for the particular drive operation is reached, and the increment (count) of drive cycles in the method will be increased for each drive cycle.

As mentioned above, the method of the invention will in particular be able to be performed using computer software. There are various types of mathematical modeling software that can be customized or programmed for performing the computational methods of the present invention, or the methods can be implemented using purpose-built computer software, as described elsewhere herein.

Referring now to fig. 4, there is shown another flow chart of another embodiment of the calculation method of the present invention, described in somewhat more detail. At the beginning of the method of FIG. 4, the redefinition of the reservoir sweep is shown at step 4-1. After the reservoir sweep is defined, the drive cycle loop, which in this example extends from step 4-2 to step 4-13, represents the performance of the same set of calculations for each selected drive cycle in the drive operation. The first step in the drive cycle 4-2 is to define reservoir and drive parameters 4-3. Some of the reservoir and drive parameters described above will remain constant throughout the drive operation, others will change continuously, and will be recalculated for each drive cycle. The reservoir and drive parameters required to perform the methods of the present invention are described specifically herein, and all reservoir and drive parameters that can be used in this manner are included within the scope of the present invention.

After the oil reservoir and the flooding parameters are captured, defined or improved for a particular flooding cycle in a flooding operation, the oil reservoir swept area is again partitioned into 3 swept sub-areas, namely a foam swept sub-area, a water swept sub-area and a gas swept sub-area. As shown in step 4-5, the longitudinal sweep efficiency and the volume sweep efficiency of each of the foam, water and gas sweep sub-zones are calculated, the method moves through additional area calculation steps 4-6, and the calculation of the recovery factor for each sweep sub-zone within the reservoir sweep area is shown in step 4-7.

Steps 4-8 again show the selection of a reservoir recovery factor calculation method, shown in more detail by decision blocks 4-9, which in one embodiment (as shown in this figure for example) is determined by comparing the total penetration area of the push-broom combination to the total push-broom area of the reservoir push-broom. If the penetration area is greater than the total push-broom area, then steps 4-11 show the selection and execution of the reservoir recovery factor calculation method based on the calculation method based on each push-broom sub-zone. Alternatively, if the total penetration area is not greater than the total push-broom area, a more basic set of equations can be used to simply sum the foam zone recovery factor, gas zone recovery factor, and water zone recovery factor together. After the calculation method or calculation of the recovery factor is performed, it is shown at step 4-12 that the calculated reservoir recovery factor can be stored. This indicates the end of the drive cycle loop, and the entire loop is completed for each selected drive cycle in the drive operation. The drive cycle loop can then be executed for other drive cycles in the drive operation until a maximum number of drive cycles is reached for a particular drive operation, for each drive cycle the increment (count) of drive cycles in the method will be increased.

The plotting of the calculated values from the stored reservoir recovery coefficients is also shown at steps 4-14 in the method of fig. 4. In effect, the reservoir recovery factor calculations for each drive cycle can be plotted on one axis of the graph against time or other reservoir and drive parameters, etc., to provide varying degrees and types of analytical tools for modeling, performing and understanding a particular drive operation. It should be appreciated that the particular type of plot shown in steps 4-14 may vary. Any type of such figures is included within the scope of the present invention, including those shown in fig. 6-17.

Oil and foam sweep efficiency and behavior within the reservoir:

in a flooding operation involving the injection of a liquid surfactant and free gas into a hydrocarbon reservoir, all three will be present in the formation at the same time, assuming that the gas, the liquid surfactant, and the foam generated by the application of external pressure to the gas and the liquid surfactant within the formation. Due to their significant differences in mobility, it is assumed that there will be three fluid-injected swept sub-zones within the reservoir, including a foam swept sub-zone, a water swept sub-zone, and a gas swept sub-zone. By assuming no overlap between them, the sum of the areas of all three swept sub-zones is considered to be the total swept area of the reservoir swept zone. Since the mobility increases from foam, liquid to gas, the sequence of these three sweep sub-zones from injection well to production well is the foam sweep sub-zone, water sweep sub-zone and gas sweep sub-zone, the gas front will reach the production well earlier than water or liquid surfactant (both of which are produced by the collapse of the foam). If each time a complete foam burst (including one water and one gas) is considered a drive cycle, then the number of drive cycles can be calculated when the front of gas or water reaches the production well. Once the operating schedule for the foam flooding is determined, then the specific breakthrough time can be estimated based on the water or gas burst size.

The key to the method and modeling simulation of the oil recovery coefficient in the reservoir to be subjected to oil displacement operation of the present invention is to understand the concept of push-broom efficiency in the formation geology. Injecting gas and fluid into the formation creates a foam that causes oil to be swept or pushed from the formation toward the production location as it moves through the formation toward the production location.

Cumulative production is assumed to be linearly related to cumulative time and cumulative injection volume before the gas front reaches the production well. The swept area over the time period was calculated as a 1:1 ratio to the total injected fluid volume. After gas breakthrough, the sweep efficiency is calculated using an improved equation for breakthrough heterogeneous sweep efficiency until the front of water reaches the production well. Then after the water reaches the production well, another equation for the liquid is used to calculate the sweep efficiency, introducing the theoretical maximum sweep efficiency to set the limits of the curve after breakthrough.

The penetration time and theoretical maximum sweep efficiency for each of the three sweep sub-zones are important variables in order to determine the impact on sweep efficiency and to determine the change in sweep efficiency with time or injection volume associated with one or more drive cycles. Due to the assumptions of these three sweep zones and the instability of the foam, the gas and water displacement fronts in the formation will reach the production well before the foam. Two more critical points in the plot of efficiency as a function of time or injection volume include the penetration time of the gas front and the penetration time of the water front. The plot of all these features is divided into three parts by these two keypoints. The portion before any injection fluid penetration is like a diagonal line. Once the gas front reaches the production well, it will turn into a curve. After a period of time, once the water front reaches the production well, the slope of the curve will increase significantly. Figure 1 is a sample plot of these features according to one embodiment of the present invention.

Defining key areas in the reservoir:

as noted above, a foam flooding of a hydrocarbon reservoir physically involves the production or use of at least one injection well and at least one production well. The at least one injection well is for injecting free gas and liquid surfactant into a formation of a hydrocarbon reservoir, which is geologically located in a suitable location such that the injected free gas and liquid surfactant will move through a geological formation of the hydrocarbon reservoir to at least one production well, sweeping or pushing oil from the formation towards the production well where oil can be produced. Most of the modeling and embodiments considered herein are based on mathematical models of only one injection well and one production well in order to model sweep efficiency and other variables. However, those skilled in the art of reservoir modeling and enhanced oil recovery techniques (such as those described herein) will recognize that other embodiments including more than one injection well and/or more than one production well can also be accepted and simulated in accordance with the remainder of the method of the present invention without departing from the scope of the present invention. All such methods are included within the scope of the present invention. Those skilled in the art will be able to understand the concept of injection wells, production wells in geological definition and the placement of injection production sites in foam flooding engineering.

In addition to the general understanding of the concept of injection and production locations in the foam flooding technology of hydrocarbon reservoirs, one of the primary steps of the method of the present invention, which typically models the oil recovery coefficients in models and methods such as those described herein, is to define a reservoir sweep. The reservoir sweep area is the volume or area of the reservoir between the at least one injection well and the at least one production well, wherein the injected gas and liquid surfactant will be injected in at least one drive cycle of a drive operation. Effectively, the reservoir sweep area is the area of the reservoir from which oil needs to be swept using a foam flooding technique. The concept of defining a reservoir sweep area will be understood by those skilled in the art of enhanced oil recovery, as this same type of concept of defining the required sweep area for a drive project is one of the first framework activities that will be performed in terms of modeling of a particular drive project. The reservoir sweep is defined to some extent by selecting locations for at least one injection well and at least one production well, again, in terms of suitable scope involving a particular drive project, as will be appreciated by those skilled in the art of enhanced oil recovery.

One of the early steps in the calculation or modeling of the factors for oil recovery in the reservoir sweep area of an oil and gas reservoir, both within the reservoir and within the reservoir sweep area, is to determine the segmentation of the reservoir sweep area into three sweep sub-areas within the reservoir sweep area. By dividing the reservoir sweep area into a foam sweep sub-area, a water sweep sub-area and a gas sweep sub-area, independent sweep efficiency and other variable calculations can be accomplished in each sub-area, and it is believed that the accuracy and speed of the method of the present invention is significantly improved over prior art methods. The definition of a swept sub-zone within a swept zone of a reservoir will be taught by the knowledge of the reservoir and the drive parameters associated with the swept zone of the reservoir. Those skilled in the art of oil and gas geology will again recognize that different methods can be employed to specifically define the sweep sub-zones, although it will generally be recognized that the definition of these zones in a reservoir sweep will be taught by knowledge of the behavior of the gas, fluid and foam components in the reservoir and the manner in which oil will be swept to the producing well within that particular geology.

To improve the accuracy of the modeling in the present method, based on knowledge of the penetration of foam, water and gas between adjacent sweep sub-zones within the reservoir sweep region, certain embodiments of the method of the present invention may further adjust the calculation of the oil recovery factor and sweep efficiency within the formation by introducing foam penetration areas, water penetration areas and gas penetration areas within which the behavior and local oil recovery factor may be further improved or altered.

FIG. 2 shows an embodiment of a reservoir sweep region according to the present invention and depicts a distribution of three sweep sub-regions therein. Assuming that the three push-broom regions have relatively sharp interfaces due to differences in their fluency, A in the figure_foam、A_waterAnd A_gasRepresenting the foam, water and gas sweep sub-zones, while the surrounding area A_btfoam、A_btwaterAnd A_btgasRepresenting the foam, water and gas breakthrough areas and the extent to which the total sweep area can be penetrated by foam, water and gas in a particular drive cycle.

Although it is not necessary to assume region a_btfoamHowever, at very low flow rates, the foam may penetrate a region where A is_btfoamIs almost equal to A_foam. This underlying mechanism is believed to make the overall calculation process more uniform. A further simplification shown in fig. 3 is used to emphasize the way the entire process is divided into three epochs. For example, while calculating the area of the water push, calculate A from the outside of the right side of the region_btfoamInitially, because the water on the front side of the foam will not push away the area just penetrated by the foam. The method is used to calculate the push-to-sweep and penetration areas for each zone.

FIG. 2 also shows the locations of injection and production wells to provide further concepts of swept volume area and overall operation for the method of estimating the recovery factor of a foam-driven reservoir as described herein.

The remainder of this description demonstrates the various iterations of the present coefficient of oil recovery modeling method performed under different parameters, and an understanding of the definitions of the push-broom sub-zones and penetration zones shown in FIG. 2 is considered to be important to the following description.

The key assumption is that:

the foam is generated by mixing the injected liquid surfactant and gas together under an external pressure differential. Gas and liquid surfactants are respectively injected into an oil and gas reservoir to form an oil displacement cycle. For each flooding cycle, a stream of surfactant solution is injected, followed by a stream of free gas. The gas and liquid surfactant will eventually separate due to foam instability. Gas and liquid surfactants are cyclically injected into the reservoir, causing foam, water and gas to be present simultaneously. Because of their significant differences in flow rates, it is assumed that there will be three swept sub-zones of injected fluid within the reservoir, including a foam swept sub-zone, a water swept sub-zone, and a gas swept sub-zone. By assuming no overlap between them, the sum of all three swept sub-zones is considered to be the reservoir swept zone.

The following are key assumptions used in the modeling embodiments and examples shown herein:

after injection of one shot of surfactant followed by another shot of free gas, foam is generated at that location;

foam collapse with the passage of time described by half-life;

foam does not regenerate once it collapses;

time is the only factor that determines the remaining foam volume. The effect of weakening the foam strength without regard to contact with oil;

foams, free gases and water (liquid surfactants) have relatively significant differences in fluidity;

the fluid with the higher fluidity travels to the front of the injected fluid, which will not reach the area that has been swept by the fluid of the lower fluidity;

two penetration cases are considered, one of which is the double front case. Due to the difference in fluidity, the gas and water breakthrough times were estimated separately. The first front end is caused by gas channeling. The second front is caused by the difference in fluidity between the gas and the water (liquid surfactant), which can result in a small increase in yield because the water drive has a higher sweep efficiency. The other case is the single front end case, which originates from the traditional water driven case.

Those skilled in the art will recognize that the present invention can also be implemented with improvements to these assumptions, and the inventors believe that all such changes to the modeling assumptions that do not depart from the intended scope are within the scope of the present invention.

Nomenclature of the terms:

the following nomenclature is used in the formulas described herein, and for reference purposes is provided in the exemplary embodiments and illustrations of concepts and measurements or values presented in the various calculations described herein:

A_btfoamfoam penetration area: area penetrated by existing foam, m²

A_btgasGas penetration area: area penetrated by existing gas, m²

A_btwaterWater penetration area: is provided withArea of penetration of water or liquid surfactant, m²

A_foamArea of foam sweeping, m²

A_gasGas swept area, m²

A_waterM is the area of water sweeping²

C_gasinfoamGas volume factor, the ratio of the volume of gas trapped inside the foam to the volume of the same mole of gas outside the foam

E_AafterBTEfficiency of area sweeping after penetration

E_ABTArea push-broom efficiency after penetration for specific fluidity ratio

E_AfoamArea sweeping efficiency of foam

E_AgasArea gas sweeping efficiency

E_AmaxTheoretical maximum push-broom efficiency with specific fluidity ratio and permeability variation

E_AwaterArea sweeping efficiency of water

E_DfoamEfficiency of foam delivery

E_DgasEfficiency of gas delivery

E_DwaterEfficiency of water delivery

E_VfoamVolume sweeping efficiency of foam

E_VgasVolumetric sweeping efficiency of gas

E_VwaterVolume sweeping efficiency of water

E_ZfoamLongitudinal sweeping efficiency of foam

E_ZgasLongitudinal sweeping efficiency of gas

E_ZwaterLongitudinal sweeping efficiency of water

f_wMoisture content

h is reservoir height, m

M is fluidity ratio

M ═ virtual fluidity ratio

PV ═ volume of injected pores

RF-reservoir oil recovery factor

RF_foamFoam zone oil recovery factor

RF_gasGas zone oil recovery factor

RF_waterWater area oil recovery factor

S_oiInitial oil saturation ratio

S_orResidual oil saturation ratio

S_wcOriginal water saturation ratio

T half-life, time for which the amount of foam present has decreased to half, h

t-elapsed time of the foam produced after a particular cycle, h

u_tSpeed of fluid injection into the reservoir, m/day

u_gasGas injection rate (SC), m³/D

u_waterLiquid surfactant injection rate (SC), m³/D

V_foamPore volume of foam sweeping, m³

V_gasPore volume of gas sweep, m³

V_waterPore volume of water sweep, m³

Change in permeability

V_iVolume of newly formed foam after one injection cycle, m³

V_leftThe residual volume of foam produced by the circulation of the injection fluid after time t, m³

V_totalfoamTotal amount of foam remaining, m³

W_injTotal volume of fluid injected (SC), m³

W_iBTTotal volume of fluid (SC) that has been injected when penetration occurred, m³

μ_oOil viscosity, cp

μ_wThe viscosity of the water is equal to the viscosity of the water,cp

phi is porosity.

Detailed method calculation:

for purposes of a more detailed description, we will now present the mathematical methods used in certain embodiments of the foam driven reservoir coefficient of recovery estimation methods described herein. The calculations below to demonstrate some embodiments of mathematical models used in accordance with the general methods of the present invention will be understood to be capable of being modified to improve or optimize the results thereof, or by modifying certain parameters or conditions therein to produce particular results within the general intended scope of the invention, all such modifications as would be recognized by those skilled in the art are intended to be included within the scope of the present invention.

Total penetration area:

the first set of calculations to be performed for a particular drive cycle in an iteration of the drive cycle loop are calculations on the total sweep area and total penetration area that require the calculation of water penetration area, gas penetration area, and foam penetration area. The penetration times of the bubbles, water and gas between the corresponding swept areas in the reservoir sweep are correlated calculations. Gas has a higher mobility than water, and water has a higher mobility than oil. The gas sweep area is further from the at least one injection well than the water sweep area, and the water sweep area is further from the injection well than the froth sweep area. Due to this particular difference in mobility ratio, the gas will reach the at least one production well before the water/surfactant and foam. The following formula uses the nomenclature described above, which shows the gas breakthrough to at least one production well:

A_BTfoam+A_BTwater+A_BTgas=A_total(1)

A_totalis the total push-broom area, which is specified by data entry or other means at the beginning of the calculation. According to FIG. 2, once this equation is implemented, it means A_BTfoam、A_BTwaterAnd A_BTgasTo a_totalMeaning that there are no more new areas to sweep the gas and the gas front reaches the production well. At this time, A_BTfoam、A_BTwaterAnd A_BTgasCan be calculated according to the following equation:

in a five-point work plan (five-spot work plan), C is 0.718. If the work plan is the inverse nine point, C is 0.525, and in the inverse seven point work plan, C is 0.743. M is the virtual fluidity ratio, which is the modified fluidity ratio for the non-homogeneous case. The fluidity ratio is determined by the fluidity ratio (M) and the permeability change (V). When V is less than 0.7, the optical fiber,

when V is greater than 0.7, the crystal,

m represents the fluidity ratio in the homogeneous case, and V is the permeability change. A. the_foam、A_waterAnd A_gasIs calculated from equations (11), (17) and (22). M_foamIs the virtual fluidity ratio of foam to oil; m_waterIs the virtual fluidity ratio of water to oil; and M_gasIs the virtual gas to oil mobility ratio.

Penetration time in water sweep sub-zone:

the penetration of water into the gas sweep sub-zone will occur after the gas penetration. In particular, breakthrough will occur within the water sweep sub-zone when the following equation is satisfied:

A_BTfoam+A_BTwater＝A_total(7)

A_totalis the total reservoir pattern area. Referring to FIG. 2, once this equation is implemented, it means A_BTfoamAnd A_BTwaterTo a_totalIndicating that there are no more new zones to sweep with water and that the water front reaches at least one production well.

Estimating pre-breakthrough recovery coefficients

If A is_BTfoam、A_BTwaterAnd A_BTgasThe sum is less than A_totalThe system is considered not to have been penetrated. The following is the next calculation used in the evaluation of the oil recovery coefficient.

Foam sweeping area:

because free gas and liquid surfactant are injected into the reservoir in bursts, the resulting volume that falls within the reservoir sweep is assumed to be equal to the sum of the injected gas and injected surfactant liquid at the reservoir pressure. A factor R is introduced to describe the situation when gas is over-injected, considering that not all gas injected into the reservoir can foam with the surfactant component. R is the ratio of the gas forming the foam in the same strand to the total amount of gas injected. In the calculation, R is considered as a constant coefficient. The gas injected but not creating foam is supposed to mix with the gas created from the collapse of the foam. The two will join together and form the front end of the gas channeling, which is also the gas sweep area mentioned earlier. The gas within the foam is compressed compared to a free gas of the same molecular weight. With respect to the ideal gas:

P_bubbleV＝nRT。

meanwhile, the gas pressure in each single bubble has the following relationship with the gas pressure outside the bubble:

γ is the surface tension of the bubble. Although the surfactant initially lowers the surface tension, surface swelling will eventually lower the surfactant concentration at the surface, increasing γ. Then, P_bubbleThe bubble is compressed as it grows.

Introducing another new coefficient, the gas volume coefficient in the bubbles C_gasinfoamDescribing the ratio of the volume of gas trapped inside the froth to the volume of the same mole of gas outside the froth, which is only a little less than 1. This factor is introduced to more accurately describe the presence of foam. In addition to its unique profile control properties, foam instability is a significant feature of foams as compared to other types of injection fluids. The half-life of the foam was introduced to calculate the remaining volume of foam in the reservoir.

V_leftIs the remaining volume of foam generated by one cycle of injected fluid after time t. V_iIs the volume of newly formed foam after one injection cycle. T represents the half-life, which is determined by the foam or blowing agent selected, and T is the time elapsed after foam generation. This equation is used to calculate the remaining volume of foam produced by one cycle injection. According to the cyclic injection method, the total amount of foam remaining can be calculated by adding together the remaining volumes of each cycle. The foam generation time is assumed to be the time when both strands of a complete cycle complete the injection. The total amount of foam remaining is calculated from the following equation:

the foam swept volume V can then be calculated using the following formula_foam：

S_wcIndicating the water saturation ratio. S_orIs the residual oil saturation, which is equal to the saturation of the end points in the foam oil relative permeability curve when the permeability of the oil is equal to 0. Push-broom area A of foam oil displacement area_foamEqual to:

volume sweeping efficiency of the foam sweeping sub-area:

according to fig. 2, the foam sweep area with good profile control performance is much smaller than the reservoir sweep area. The front end of the foam sweep sub-zone will hardly reach the at least one production well. Assuming that the volume of fluid injected is equal to the volume of reservoir fluid swept, then the swept volume of fluid is equal to the following equation,

E_Vfoam＝E_Zfoamx E_Afoam

E_Afoamrepresents the longitudinal sweeping efficiency in the foam sweeping sub-area, which is equal to:

E_Zfoamequal to the longitudinal push-broom efficiency, calculated according to Craig's experimental model (1957). The model provides a method for calculating longitudinal push-broom efficiency using different fluidity ratios and viscous force to gravity ratios.

The following shows the definition of the ratio of viscous force to gravity:

in the formula, u_tIs the rate of injection of fluid in the reservoir, in m/day. Mu.s_oIs the viscosity of the oil, measured in Pa s. x is the distance between the at least one injection well and the at least one production well. k is the horizontal permeability in md. Δ ρ is the density difference between the injected fluid and the oil. The fitted curve equation showing this relationship taken from the prior art scheme is:

m represents the fluidity ratio between the foam and the oil. This equation can be used to calculate the longitudinal sweeping efficiency within the froth sweeping sub-zone.

Discharge efficiency in the foam sweeping sub-area:

in light oil reservoirs, the foam has a much higher viscosity than brine or oil and acts as a profile control agent, for which reason the motion of the foam flooding is assumed to be a piston-type displacement. The efficiency of the discharge is considered constant in this assumption, which is equal to the following equation, where S_oiIs the initial oil saturation. S_orIs the residual oil saturation. They are obtained from the end-point values of the relative permeability curves:

by definition, the bubble zone recovery factor is equal to the product of the volumetric sweep efficiency and the displacement efficiency multiplied using, for example, the following equation:

RF_foam＝E_Dfoam×E_vfoam(16)

water-push broom sub-area:

the next area and calculation to implement the method of the present invention involves a water push-broom sub-area. The water sweep area is derived from the collapse of foam, located in front of the foam sweep area, where λ_surfactantThe volume ratio of the surfactant solution in each injection cycle is expressed. V_iIs the total injected fluid volume per injection cycle:

the volume sweeping efficiency of the water sweeping sub-zone is calculated as:

E_Vwater＝E_Zwater×E_Awater(18)

E_Awateris the volume sweeping efficiency of the water sweeping sub-zone:

E_Zwateris the longitudinal sweeping efficiency of the water sweeping sub-zone.The calculation of the longitudinal sweeping efficiency of the water sweeping sub-zone is the same as the calculation of the longitudinal sweeping efficiency of the foam sweeping sub-zone, which is also calculated with different fluidity ratios according to the model of Craig.

Drainage efficiency in water-swept sub-area

Prior to breakthrough, all of the injected volume contributes to the recovery of new areas within the reservoir. The average saturation of the displaced fluid before the front end remains constant until the injected fluid penetrates. For this reason, the discharge efficiency also remains constant.

In this calculation, S_oiIs the initial oil saturation, S_orIs the residual oil saturation. They are obtained from the end points of the relative permeability curve.

Oil recovery coefficient in water-swept sub-zone:

by definition, the oil recovery factor is equal to the volume of oil or the product of the volumetric sweep efficiency multiplied by the displacement efficiency:

RF_water＝E_Dwater×E_vwater(21)

gas purge sub-zone:

the same set of calculations are used in the gas sweep sub-zone. First, the gas sweep area needs to be calculated, which results from the collapse of the foam and is located before the water sweep sub-zone due to the difference in fluidity.

In this calculation, A_gasIs the volume ratio of the gas in the cycle to the volume of all the fluid injected. c is a coefficient considering reaction and gas consumption. For example, if air foam injection is selected, c equals 0.9496, indicating CO produced during the low temperature oxidation process₂Absorption of (2).

The volume sweeping efficiency in the gas sweeping sub-zone is equal to E_Vgas：

E_Vgas＝E_Zgas×E_Agas(23)

E_AgasIs the sweep efficiency in the gas sweep sub-zone:

E_Zgasis the longitudinal sweeping efficiency in the gas sweeping sub-zone. The calculation of the longitudinal sweeping efficiency of the gas sweeping sub-zone is the same as the calculation of the longitudinal sweeping efficiency in the foam sweeping sub-zone, also calculated with different fluidity ratios according to the Craig model.

All of the injected volume contributes to the recovery of new areas within the reservoir prior to breakthrough. The average saturation of the previously displaced fluid of the front end remains constant until the injection fluid penetrates. For this reason, the delivery efficiency is also kept constant, where S_oiIs the initial oil saturation, S_orResidual oil saturation ratio:

the gas sweep sub-zone is followed by the gas zone oil recovery factor. By definition, the oil recovery coefficient is equal to the product of the volumetric sweep efficiency multiplied by the displacement efficiency:

RF_gas＝E_Dgas×E_Vgas(26)

the reservoir recovery factor RF can be calculated according to the recovery factor of each zone:

RF＝RF_foam+RF_water+RF_gas(27)

if A is_BTfoam、A_BTwaterAnd A_BTgasThe sum is greater than A_totalThe system is considered to have penetrated:

A_BTfoam+A_BTwater+A_BTgas＞A_total

in the case where the gas has penetrated but the surfactant solution has not, the volume sweep efficiency will be calculated using empirical equations from the homogeneous case to estimate the maximum area sweep efficiency after penetration. Then the original equation is changed to account for the heterogeneous case using fig. 2. For a homogeneous reservoir, the maximum area sweep efficiency at penetration can be calculated as:

c is a coefficient relating to the well pattern distribution. When the work plan is five points, C is 0.718. When the work plan is the inverse nine points, C is 0.525, or when the work plan is the inverse seven points, C is 0.743.

For a homogeneous reservoir, the maximum area sweep efficiency after penetration was calculated using the following equation:

where D is a coefficient relating to the well pattern distribution. When the work plan is five points, D is 0.2749. When the work plan is the inverse nine point, D is 0.201.

For heterogeneous reservoirs, the results are changed according to the pattern. The change in maximum area push-broom efficiency calculation focuses on two points: maximum area sweep efficiency upon penetration and theoretical maximum area sweep efficiency for a particular injected fluid. Permeability change (V) is selected as a variable to exhibit the effects of heterogeneity in accordance with references relating to push-broom efficiency calculations for heterogeneous reservoirs. Since the existing equation for maximum area push-broom efficiency at penetration has only one variable (i.e., fluidity ratio), it is critical to derive an intermediate variable. This intermediate variable can link the fluidity ratio and permeability changes to the sweep efficiency. According to the pattern, the maximum area push-broom efficiency decreases as the permeability change increases. Meanwhile, as the fluidity ratio increases, the maximum area sweeping efficiency also decreases. Once the mobility ratio and permeability change are determined, the maximum area sweep efficiency from the pattern is equal to the maximum area sweep efficiency from other higher mobility in a homogeneous reservoir. This higher fluidity ratio is an intermediate variable as described earlier, and is referred to as a virtual fluidity ratio. The virtual mobility ratio is defined as the mobility ratio in the swept region of the homogeneous reservoir that can achieve the same maximum area sweep efficiency with other mobility ratios when a particular permeability changes.

According to this physical interpretation, the permeability change of the swept area of the heterogeneous reservoir is always greater than 0, and therefore the virtual mobility is always higher than the original mobility. The maximum area push-broom efficiency equation at breakthrough after taking into account heterogeneity is shown below. M is the virtual fluidity ratio.

Where C is a coefficient relating to the well pattern distribution. When the work plan is five points, C is 0.718. When the work plan is the inverse nine points, C is 0.525, or when the work plan is the inverse seven points, C is 0.743.

After breakthrough, the maximum area sweep efficiency after breakthrough in the sweep region of the heterogeneous reservoir is calculated using the following equation:

when the work plan is five points, D is 0.2749. When the work plan is the inverse nine point, D is 0.201. X is the push-sweep efficiency E set to tend to the maximum area when the current fluidity ratio and permeability change_AmaxThe maximum area of (a) is the coefficient of the sweep efficiency.

The maximum area sweep efficiency of fig. 2 is the experimental result when the WOR equals 25 or 96.15% water percentage. Assuming that at least one production well is stopped at this time, the maximum area sweep efficiency is considered. EA (M, V) can be divided into two parts for curve fitting, a smooth part L at lower permeability changes₁With the increase of heterogeneity, the maximum area sweeping efficiency has little change; and a diagonal line portion L at a relatively low permeability of a relatively high degree₂Which varies significantly with small changes in heterogeneity. The position of the segmentation point of the two parts is not constant, which is a function of the fluidity ratio.

V_C＝-0.063×ln(M+0.1)+0.5473 (32)

M is the initial fluidity ratio. V_cIs a smooth part L₁And a diagonal line portion L₂The division point in between. According to the curve fitting result, when the permeability change V is less than V_cThe maximum area sweeping efficiency is then the following equation:

E_Amax＝-0.07076V+0.8606-0.0605×ln(M+0.1) (33)

when the permeability change V is greater than or equal to V_cThe maximum area sweeping efficiency of the oil reservoir sweeping area is the following equation:

then X is determined according to the equation of the maximum inhomogeneous area sweeping efficiency after penetration as follows:

and then, the X is substituted back to the original equation, so that the maximum inhomogeneous area push-broom efficiency after penetration can be calculated.

Longitudinal pushing and sweeping efficiency

The next set of calculations involves the calculation of the longitudinal push-broom efficiency. The longitudinal push-broom efficiency is calculated in the same way:

then, the volume sweep efficiency is calculated as E_V＝E_Zx E_A。

Efficiency of delivery after penetration

The efficiency of the discharge can be calculated using the following equation, where S_dIs the saturation ratio, S, of the fluid being displaced_wcRepresents the water saturation ratio:

the cumulative injection volume (PV) can be estimated from the cumulative injection volume, where B_wIs the volume factor of saline, W_injIs the cumulative injection volume, Φ is the porosity, PV is the multiple of the injection pore volume:

according to the flooding front-end theory, PV is equal to the inverse of the differential of the water split to the water saturation:

since the ratio of the relative permeability of oil to the relative permeability of water is a function of the water saturation, it can be written in the following form (a, b can be estimated using linear regression):

the water split flow can be expressed by the following equation, where μ_oAnd mu_wIs the viscosity of the oil and brine:

in the next step that follows, the differential of the water split flow rate and the water saturation rate can be written in the form:

the fluidity ratio for a particular PV can be estimated from this equation. The flow rate ratio just calculated can be used to estimate the water split flow rate at a particular time. From the water diffusion equation, the average water saturation can be calculated from the split water flow:

finally, the average delivery efficiency can be calculated as follows:

oil recovery after breakthrough coefficient:

by definition, the reservoir recovery factor is equal to the product of the volumetric sweep efficiency multiplied by the displacement efficiency:

RF＝E_D×E_V(46)

once the water has achieved penetration, it will flow into the area swept by the gas before entering the new area according to the flow fluid theory. This mechanism acts like a permeability change, which means that a dominant channel is formed in the area swept by the gas. To correctly express this mechanism, a resistance factor Kx for permeability is introduced.

Kv^*＝kx×V

This Kv is then used instead of the original permeability change V to calculate the water-permeated recovery factor.

Fig. 6-17 show sample plots of a flooding operation generated with different reservoir and flooding parameters in accordance with the method of the present invention. These figures are used in a generic sense to demonstrate the utility and performance of the methods of the invention, but should not be construed as limiting the scope of the invention described herein, which is intended to cover the full scope of the claims.

In each of fig. 6-17, the curves labeled as double front curves are formed by using the coefficient of recovery estimation method for foam-driven reservoirs described herein, while the single front curves are a simplification of the model, taking into account only one gas front penetration. The curves marked with simulations were given by using computer numerical simulation software (CMG).

Computer software:

FIGS. 18 and 19 are flow diagrams showing one embodiment of the steps performed in the computer software iterations of the method of the present invention. Again, those skilled in the art of computer software design will recognize that many different types of software can be used, including software specifically built for this purpose, or existing mathematical modeling software that can be customized to perform the calculations required for the performance of the method. The methods of fig. 18 and 19 will be understood to generally describe the methods to be performed by processor instructions within a computer-readable storage medium executed by a computer, into which other formulas and methods can be introduced without departing from their intended scope and coverage, as generally described herein.

At the beginning of the method of FIG. 18, the reservoir and drive parameters are shown as captured or data input at step 18-1. The capture of reservoir and drive parameters typically includes capturing parameters such as mobility ratio and permeability changes. These can be captured from data stored on a sensor bus, a personal data entry terminal or display, or a diskette or other memory or storage medium.

Once the reservoir and drive parameters are captured, step 18-2 shows calculating the longitudinal sweep efficiency within the reservoir sweep region, the flow chart of FIG. 18 shows that equation 14, described above, is the sample equation that will be used in these calculations, and each step in the flow chart of FIG. 18 represents a mathematical model or equation from the rest of the specification that will be used in the performance of the particular step. Again, of course, even if the specific formulas for implementing the commercial process steps were changed, the same overall process would still be implemented and would be considered to be within the scope of the present invention.

After the longitudinal sweep efficiency is calculated at 18-2, the drive cycle is started, i.e., the technique related to the reservoir sweep coefficient is performed once for each selected drive cycle in the drive cycle continuing between steps 18-3 through 18-17 of the figure.

The first step in the drive cycle shown in fig. 18 is to calculate the various areas, including the foam swept area, the gas swept area, and the water swept area, as well as the foam through area, the gas through area, and the water through area. The penetration area is also described in more detail elsewhere herein. Determining the presence or magnitude of breakthrough has a significant impact on further down-calculations in the method within the drive cycle.

After the area calculations shown at 18-4 are completed, step 18-5 indicates that the bubble zone recovery factor is calculated using equations 8-16.

After the foam zone oil recovery factor (which is the oil recovery factor or oil recovery contribution from the foam swept sub-zone) is calculated, step 18-6 shows a first logic block or step for determining the next applied calculation in the method of the present invention. The sum of the foam penetration area, the water penetration area, and the gas penetration area is compared to the total sweep area of the sweep region of the reservoir within the reservoir. If the sum of the three penetration areas is greater than the total push-broom area, the calculation logic returns to step 18-10, and if the total push-broom area is greater than the sum of the three penetration areas, the calculation moves to step 18-7. This effectively constitutes a choice of method for calculating the oil recovery factor.

Step 18-7 shows calculating the water zone production coefficient using equations 17-21 and then the gas zone production coefficient using equations 22-26. Having calculated the individual coefficients of foam zone, gas zone and water zone recovery coefficients, the reservoir recovery coefficients can then be calculated at step 18-9 using equation 27 and stored at data storage step 18-16.

Or moving to the second logic step of 18-10, with reference to the total push-broom area being exceeded by the total penetration area, the sum of the foam penetration area and the water penetration area will be compared to the total push-broom area. If the total sweep area is less than the sum of the foam penetration area and the water penetration area, then at step 18-11 the water zone recovery factor is calculated in the water phase using equations 29-46, and then the reservoir recovery factor is calculated by adding the foam zone recovery factor and the water zone recovery factor. On the "no" branch of the logic block of step 18-10, the gas zone production coefficients calculated in the gas phase using equations 17-21, then to step 18-14 using equations 29-46. Finally, at step 18-15, the reservoir recovery factor will be calculated according to equation 27.

After each drive cycle completes the calculation of the reservoir recovery factor and stores it at step 18-16, the drive cycle loop terminates at step 18-17. If the maximum number of drive cycles selected by the method has not been completed, the loop will return to step 18-3 and move to the calculation of the next drive cycle by incrementing its value. Alternatively, if the maximum number of cycles has been reached, the drive cycle will be terminated and the stored calculated reservoir recovery factor can be used in a mapping or other analysis.

The overall development of a computer program capable of executing a mathematical model such as described herein will be understood by those skilled in the art of software design, and all methods for developing purpose-built or customized modeling software that perform the methods described herein are intended to be encompassed within the scope of the present invention.

Overall results:

tables 1 and 2 show two sets of calculations calculated according to the conventional CMG method and the method of the present invention for different reservoir and flooding parameters (i.e., different permeability changes and injection rates). Table 1 shows the results for the single front end case, with no sudden production after gas breakthrough. Table 2 shows the results for the dual front-end case, where the effect of different fluidity ratios after breakthrough is taken into account.

The table lists the oil recovery factor after 5 years of production and 10 years of production in each case. The results of the prior method CMG were compared with the results of the invention, and the difference in percentage was also calculated for each case in the table.

Based on these results, both methods can be used to estimate the oil recovery factor, and the present invention can provide accurate results compared to CMG. Based on comparison with simulations, the dual front-end approach provides better results in the case of lower heterogeneity reservoirs or in the early stages of reservoir production, and the single front-end approach provides better results in the case of higher heterogeneity reservoirs or in the later stages of reservoir production.

V is the permeability change, which is used to describe the heterogeneity of the reservoir. u. of_gasIs the gas injection rate (SC), u_waterIs the surfactant solution injection rate (SC).

Table 1: comparison of results between single front end methods and simulations

Table 2: comparison of results between dual front-end methods and simulations

It should be recognized that the specific steps of the methods and computer software of the systems described herein are not considered limiting upon the scope of the invention. Those skilled in the art will readily recognize that materials and components can be selected to meet the objectives of the present invention without any inventive effort.

It will be apparent to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the spirit of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms "comprises" and "comprising" should be interpreted as referring to elements, components, or steps in a non-exhaustive manner, indicating that the elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced.

Claims

1. A method of estimating the recovery factor in a foam-driven reservoir, the recovery factor in the foam-driven reservoir being the reservoir recovery factor, the method comprising:

defining a reservoir sweep area as a volumetric region within the reservoir between the at least one injection well and the at least one production well, wherein gas and liquid surfactants injected into the at least one injection well during at least one drive cycle sweep oil through the reservoir sweep area to the at least one production well for production therefrom;

executing a drive circulation loop, and modeling the oil reservoir oil recovery coefficient in the oil reservoir push-broom area during each drive circulation by the following steps:

determining the oil deposit and oil displacement parameters of the oil deposit push-broom area according to the current states of the gas and the liquid surfactant injected into the oil deposit push-broom area;

using the reservoir and the displacement parameters, subdividing the reservoir sweep area into three sweep sub-areas: a foam sweeping sub-area, a water sweeping sub-area and a gas sweeping sub-area;

in the calculating step:

calculating the longitudinal push-broom efficiency and the volume push-broom efficiency in each push-broom sub-area;

calculating the total push-broom area of the oil deposit push-broom area, wherein the total push-broom area is the volume area of the oil deposit push-broom area pushed by foam in the current oil displacement cycle;

calculating a foam sweeping area, wherein the foam sweeping area is the volume area of a foam sweeping sub-area swept by foam in the current oil displacement cycle;

calculating a water push-broom area, wherein the water push-broom area is the volume area of a water push-broom sub-area which is pushed away by water in the current oil displacement cycle;

calculating the gas sweeping area, wherein the gas sweeping area is the volume area of a gas sweeping sub-area swept by gas in the current oil displacement cycle;

calculating a foam penetration area, wherein the foam penetration area is the volume area of a foam sweeping sub-area penetrated by the existing foam in the flooding cycle and comprises the foam sweeping area and a foam bypass area around the foam sweeping area due to the mobility difference between the foam and oil;

calculating a water breakthrough area, which is the volumetric area of a water swept sub-area within the flooding cycle that is penetrated by existing water, including the water swept area and its surrounding water bypass area due to the difference in mobility between water and oil;

calculating the gas penetration area, wherein the gas penetration area is the volume area of a gas swept area penetrated by the existing gas in the flooding cycle, and comprises the gas swept area and the area of a gas bypass around the gas swept area due to the mobility difference between the gas and the oil; and

calculating a total penetration area that is the sum of the foam penetration area, the water penetration area, and the gas penetration area;

in the oil recovery coefficient estimation step:

calculating an oil recovery coefficient of the foam area, wherein the oil recovery coefficient is an oil recovery coefficient contributed by the foam pushing and sweeping sub-area;

calculating the oil recovery coefficient of the water area, wherein the oil recovery coefficient is the oil recovery coefficient contributed by the water pushing and sweeping sub-area;

calculating the oil recovery coefficient of the gas area, wherein the oil recovery coefficient is the oil recovery coefficient contributed by the gas push-broom sub-area;

selecting an oil reservoir oil recovery coefficient calculation method to be used by comparing the numerical values of the total penetration area and the total push-broom area; and

and executing the selected reservoir oil recovery coefficient calculation method.

2. The method of claim 1, further comprising storing the calculated reservoir recovery factor at the completion of each iteration of the drive cycle.

3. The method of claim 2, further comprising plotting at least one graph after completion of the drive cycle loop, the stored calculated reservoir recovery factor for each drive cycle being plotted on one axis of the graph.

4. The method of claim 3, wherein the relative time of the drive cycle is plotted on another axis of the at least one graph.

5. The method of claim 3, wherein the reservoir and drive parameters of the reservoir or drive operation are plotted on a second axis of the at least one graph.

6. The method of claim 1, wherein the reservoir and drive parameters are used according to the needs of each calculation within the calculating step.

7. The method of claim 1, wherein the reservoir and drive parameters are used according to the need for each calculation in the coefficient of oil recovery estimation step.

8. The method of claim 1, wherein if the total penetration area is less than the total push-broom area, the selected reservoir recovery factor calculation method adds the foam zone recovery factor, the water zone recovery factor, and the gas zone recovery factor to obtain the reservoir recovery factor.

9. The method of claim 1, wherein if the total penetration area is greater than the total push-broom area, the selected reservoir recovery factor calculation method comprises:

for each of the three push-broom sub-regions:

calculating the maximum area push-broom efficiency during penetration;

calculating the maximum area push-broom efficiency after penetration according to the maximum area push-broom efficiency during penetration;

calculating the volume sweeping efficiency according to the maximum area sweeping efficiency after penetration and the longitudinal sweeping efficiency;

calculating the discharge efficiency; and

calculating a sub-zone oil recovery coefficient for the sub-zone using the displacement efficiency and the volume sweep efficiency corresponding to the sub-zone; and adding the calculated sub-area oil recovery coefficients of all three push-broom sub-areas to obtain the oil reservoir oil recovery coefficient.

10. The method of claim 9, wherein the reservoir and drive parameters are used according to the needs of each calculation that constitutes the reservoir recovery factor calculation method.

11. The method of claim 1, wherein the number of drive cycles is 1.

12. The method of claim 1, wherein the number of injection wells is 1.

13. The method of claim 1, wherein the number of injection wells is greater than 1.

14. The method of claim 1, wherein the number of drive cycles is greater than 1.

15. The method of claim 1, wherein the number of production wells is 1.

16. The method of claim 1, wherein the number of production wells is greater than 1.

17. The method of claim 1, wherein the reservoir and drive parameters are selected from the group consisting of at least one of mobility ratio and permeability change.

18. A non-transitory computer-readable storage medium for estimating recovery factors in a foam-driven hydrocarbon reservoir, the computer-readable storage medium comprising instructions that, when executed by a computer, cause the computer to:

for each oil displacement cycle:

in the calculating step:

calculating a foam sweeping area which is the volume area of a foam sweeping sub-area swept by foam in the current oil displacement cycle;

calculating a water push-broom area which is the volume area of a water push-broom sub-area pushed by water in the current oil displacement circulation;

calculating the gas swept area, which is the volume area of the gas swept sub-area swept by the gas during the current oil displacement cycle;

calculating a foam penetration area, which is the volume area of a foam sweeping sub-area penetrated by the existing foam in the flooding cycle, and comprises the foam sweeping area and the foam bypass area around the foam sweeping area due to the fluidity difference between the foam and the oil;

calculating a water breakthrough area, which is the volumetric area of the water swept sub-area within the flooding cycle that is penetrated by existing water, including the water swept area and its surrounding water bypass area due to the difference in mobility between water and oil;

calculating a gas breakthrough area, which is the volumetric area of the gas swept area within the drive cycle that is penetrated by the existing gas, including the gas swept area and its surrounding gas bypass area due to the difference in mobility between the gas and the oil; and

in the oil recovery coefficient estimation step:

19. The computer readable storage medium of claim 18, wherein the reservoir and drive parameters are used according to the needs of each calculation within the calculating step.

20. The computer readable storage medium of claim 18, wherein the reservoir and drive parameters are used according to the need for each calculation in the coefficient of oil recovery estimation step.

21. The computer readable storage medium of claim 18, wherein if the total penetration area is less than the total push-broom area, the selected reservoir recovery factor calculation method adds the foam zone recovery factor, the water zone recovery factor, and the gas zone recovery factor to obtain the reservoir recovery factor.

22. The computer readable storage medium of claim 18, wherein if the total penetration area is greater than the total push area, the selected reservoir recovery factor calculation method comprises:

for each of the three push-broom sub-regions:

calculating the maximum area push-broom efficiency during penetration;

calculating the discharge efficiency; and

23. The computer readable storage medium of claim 22, wherein the reservoir and drive parameters are used according to the needs of each calculation that constitutes the reservoir recovery factor calculation method.

24. The computer readable storage medium of claim 18, wherein the instructions further configure the computer to store the reservoir recovery factor calculated in each drive cycle.

25. The computer readable storage medium of claim 24, wherein the method further comprises plotting the reservoir recovery factor for each drive cycle on one axis of the graph.

26. The computer readable storage medium of claim 18, wherein the reservoir and drive parameters are selected from the group consisting of at least one of mobility ratio and permeability change.