US20090194281A1

US20090194281A1 - Optimum salinity profile in surfactant/polymer flooding

Info

Publication number: US20090194281A1
Application number: US12/023,738
Authority: US
Inventors: James J. Sheng
Original assignee: Total E&P USA Inc
Current assignee: Total E&P Research and Technology USA LLC
Priority date: 2008-01-31
Filing date: 2008-01-31
Publication date: 2009-08-06

Abstract

An optimum salinity profile in surfactant/polymer flooding from formation water to post-flush drive that leads to the highest oil recovery factor is shown. The optimum salinity determined from core-flooding experiments is preferably used in the surfactant slug. The surfactant slug is protected from deterioration by the injection of cushion slugs immediately before and after the injection of the surfactant slug in a reservoir wherein the cushion slugs have the same salinity or about the same salinity as the surfactant slug. According to embodiments, a salinity lower than the lowest salinity of Type III, C_sel, is used in the post-flush drive, while formation water could be of any salinity.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is related to co-pending application, U.S. patent Ser. No. XX/XXX,XXX, [Attorney Docket No. 55805/P003US/10712257], filed ______, entitled “DETERMINATION OF AN ACTUAL OPTIMUM SALINITY AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION FOR SURFACTANT/POLYMER FLOODING,” concurrently filed herewith, the disclosure of which is incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates to the field of Enhanced Oil Recovery (EOR) from reservoirs using a surfactant system. Specifically, the disclosure relates to the design of an optimum salinity profile for surfactant flooding of a reservoir.

BACKGROUND OF THE INVENTION

Petroleum (crude oil) is a finite resource that naturally occurs as a liquid in formations in the earth. Usually, crude oil is extracted by drilling wells into underground reservoirs. If the pressure of the crude oil underground is sufficient, then that pressure will cause the oil to rise to the surface. When pressure of the crude oil is sufficiently high, recovery simply involves constructing pipelines to carry the crude oil to storage facilities (e.g. tank batteries). This is known as primary recovery. If the pressure of the crude oil in the reservoir is insufficient to cause it to rise to the surface, then secondary means of recovery have to be used to recover the oil. Secondary oil recovery includes: pumping, water injection, natural gas reinjection, air injection, carbon dioxide injection or injection of some other gas into the reservoir.
The extraction of crude oil from a reservoir by conventional (primary/secondary oil) recovery technology, however, leaves behind a significant portion of the total amount of oil in that reservoir. Traditionally, the oil recovered from a reservoir, using conventional technology as compared to the total amount of oil in the reservoir, is about 33%. Thus, on average, when only conventional methods are used, approximately 67% of the oil in a reservoir is “stranded” in that reservoir. Consequently, EOR processes are used to increase crude oil recovery factors from reservoirs.
One method of EOR involves the use of surfactants. A surfactant is a wetting agent that lowers the interfacial tension between fluids or substances. Applied in oil recovery, surfactants reduce the interfacial tension that may prevent oil droplets from moving easily through a reservoir. The use of surfactants in aiding oil to move easily through the reservoir involves the creation of microemulsions. Microemulsions are generally clear, stable, mixtures of oil, water and surfactant, sometimes in combination with a cosurfactant. By themselves, oil and water are immiscible but when oil and water are mixed with the appropriate surfactant, the oil water and surfactant are brought into a single microemulsion phase. The microemulsion's salinity affects the microemulsion's effectiveness in enhancing the recovery of oil from a reservoir. Salinity is a measure of salt content.
To make the best use of the microemulsion system, experiments have been developed to determine what is the ideal salinity of the microemulsion system for surfactant flooding. Traditionally, these experiments have focused on identifying an optimum salinity based on interfacial tension (IFT). However, co-pending application DETERMINATION OF AN ACTUAL OPTIMUM SALINITY AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION FOR ENHANCED OIL RECOVERY discloses a novel method of determining the actual optimum salinity to be used in surfactant flooding.
To determine the actual optimum salinity, oil samples are taken from an oil reservoir. Then, aqueous surfactant systems of a wide range of salinities are equilibrated with the oil in question. Equilibrations are carried out in glass-stoppered graduated cylinders, which are shaken and then allowed to sit at a constant temperature until volumetric readings remain constant with time (for example, a 24 hour period). Alternatively, equilibration may be done in pipettes or other similar laboratory equipment.
The number of phases and the volumes of these phases at equilibrium, for each salinity tested, are then recorded. Graphs of volume versus salinity are plotted. From these graphs, three regions are identified. The first region is that of intermediate salinities where three phases exist at equilibrium—(1) a micremulsion phase between (2) an oil phase and (3) a water phase. This is the region of a Type III microemulsion system with a lower boundary of C_seland an upper boundary of C_seu. Accordingly, C_selis the lowest salinity at which a three phase microemulsion system exists at equilibrium and C_seuis the highest salinity at which a three phase microemulsion system exists at equilibrium. Also, the midpoint between C_seland C_seu, can be identified from the graph. This midpoint is defined as the optimum salinity by conventional methods.
When the salinities are lower than C_sel(the lowest Type III salinity), the microemulsion system is known as a Type II(−) system. At these lower salinities, two phases will exist—(1) a microemulsion phase below (2) an oil phase. When the salinities are higher than C_seuthe (the highest Type III salinity) the microemulsion system is known as a Type II(+) system. At these higher salinities, two phases will exist—(1) a microemulsion phase on top of (2) a water phase.
After the salinity ranges of each of microemulsion systems Type II (−), Type III and Type II (+) have been defined, the best microemulsion system type for oil recovery is determined. To determine which microemulsion system is best for recovering oil from the reservoir, core flood experiments are run on at least one salinity of each system type. A salinity is selected from each of the salinity ranges Type II (−), Type III and Type II (+). Core flood experiments are run, with each of these selected salinities to determine which salinity provides the highest oil recovery factor. The core flood may be run, in the laboratory, on a sample of the rock formation containing the oil. In running the core flood experiments, the microemulsion system type with the highest oil recovery factor is identified.
Once the actual optimum system type has been determined, the next step is to determine the actual optimum salinity within this optimum system type. This is necessary, because although at least one core flood experiment would have been done for the actual optimum microemulsion system type, the salinity tested in that experiment may not be the salinity that provides the highest oil recovery in the actual optimum microemulsion system type. Accordingly, further core flood experiments are run on a series of salinities selected from the actual optimum microemulsion system type. The salinity with the highest recovery factor, of this series of salinities, is the actual optimum salinity.
However, according to the current state of the art, the optimum salinity is defined as the average of the lower boundary of C_seland the upper boundary of C_seuof a Type III microemulsion system; and this optimum salinity is applied, during EOR, in a negative salinity gradient. A negative salinity gradient means that starting from the salinity of the formation water (water naturally occurring in the rock formation of a reservoir), the salinity of each slug of the surfactant flooding system injected into the reservoir, during EOR, is lower than the formation water or the previously injected slug. For example, if the sequence of injections in surfactant flooding of a reservoir is first, a preflush slug, second, a surfactant/polymer slug and third a polymer/water drive slug, the negative salinity gradient dictates that the formation water will have a salinity greater than all the injected slugs. The preflush slug will have the next highest salinity. The surfactant/polymer slug will have an actual optimum salinity which is lower than the preflush slug and the polymer/water drive slug will have the lowest salinity. In other words, salinity is progressively reduced as fluid is injected into the reservoir. This negative salinity gradient is widely used. Therefore, the current general recovery factors in EOR, using surfactant flooding, reflects the recovery factors generally achieved by a negative salinity gradient system.

BRIEF SUMMARY OF THE INVENTION

In arriving at the present invention, it was discovered that a negative salinity gradient, in most scenarios, does not provide the highest oil recovery factor in EOR. First, apart from providing relatively low recovery factors, a negative salinity gradient is not effective in all cases. Negative salinity gradients are only applicable when the formation water is of high salinity. Indeed, formation water is usually of high salinity. However, not all formation water is of higher salinity than the salinity of a chosen surfactant. Moreover, constant salinity gradient (all injected slugs having the same salinity equal to the formation water) and positive salinity gradient (opposite of negative salinity gradient), are rarely used because they generally provide low oil recovery factors.
Second, the negative salinity gradient does not adequately maintain the designed properties of the surfactant slug as the surfactant slug proceeds through a reservoir. In other words, the properties of the surfactant slug, including salinity, deteriorate significantly once it progresses through the reservoir in a negative salinity gradient system because of salinity dilution. This deterioration of the properties of the surfactant flood, is adverse to achieving good oil recovery factors. For example, there may be diffusion to or from the surfactant slug depending on the salinity of the materials, such as formation water, in the reservoir causing the microemulsion system to become less desirable.
Therefore, in accordance with embodiments of the present invention, a method of recovering oil from a reservoir includes protecting the surfactant slug from deterioration by injecting cushion slugs before and after the injection of the surfactant slug in a reservoir where the cushion slugs have the same salinity or about the same salinity as the surfactant slug. In one embodiment, the surfactant salinity that is protected by cushion slugs is determined by experiments where the determined salinity is a function of parameters other than, but including IFT.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. The novel features which are believed to be characteristic of the invention, both as to its organization and method of operation, together with further objects and advantages will be better understood from the following description when considered in connection with the accompanying figures. It is to be expressly understood, however, that each of the figures is provided for the purpose of illustration and description only and is not intended as a definition of the limits of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:

FIG. 1 shows a comparison of oil recovery factors with the use of a negative salinity gradient and oil recovery factors with the use of the optimum salinity profile; and

FIG. 2 is a schematic diagram showing one embodiment of the invention as an optimum salinity profile.

DETAILED DESCRIPTION OF THE INVENTION

In arriving at the present invention, the hypothesis that the negative salinity gradient does not always provide the best oil recovery factors in EOR was tested by conducting simulation studies to compare oil recovery factors using the negative salinity gradients with recovery factors when the principles of the present invention are applied in an optimum salinity profile. The simulations were conducted on a chemical flood simulator known as the University of Texas Chemical Compositional Simulator, UTCHEM. UTCHEM is a three-dimensional, multiphase, multicomponent, numerical simulator. From the simulation results, it was discovered that an optimum salinity profile embodying the principles of this invention, in every simulated case, provided a higher oil recovery factor than a negative salinity gradient.

Simulation Example

Input Data to UTCHEM

For the UTCHEM simulations, a fine core-scale model was used. The grid blocks used are 80×1×1 which is a ID model. The length is 0.745 ft. Some of the reservoir and fluid properties are listed in Table 1.

TABLE 1

Reservoir and Fluid Properties

	Porosity	0.3
	k_H, mD	200
	k_V, mD	100
	Initial water saturation	0.2
	Water viscosity, cP	1
	Oil viscosity, cP	5
	Formation water salinity, meq/ml	0.4
	Assumed Surfactant data:
	Optimum salinity, meq/ml	0.365
	lower salinity, meq/ml	0.345
	upper salinity, meq/ml	0.385

The Microemulsion Systems Used in the Simulations

Simulations to compare oil recovery factors of the negative salinity gradient with oil recovery factors of an optimum salinity profile were run using systems with the following salinity profiles:

	TABLE 2

	Salinities (meq/ml)

		Second	Third Slug -
	First Slug -	Slug -	Polymer and
System	Preflush Water	Surfactant	Water Drive

Negative Salinity	0.415	0.365	0.335
Gradient

	TABLE 3

	Salinities (meq/ml)

	First Slug-	Second	Third		Fifth Slug-
	Preflush	Slug-	Slug-	Fourth Slug-	Polymer
System	water	Cushion	Surfactant	Cushion	Water Drive

Optimum	0.415	0.365	0.365	0.365	0.335
Salinity
Profile

The negative salinity gradient system has slugs injected in the following order, preflush water of 0.415 meq/ml salinity, surfactant slug of 0.365 meq/ml salinity and then polymer and water drive of 0.335 meq/ml salinity. The optimum salinity profile has slugs injected in the following order, preflush water of 0.415 meq/ml salinity, cushion slug of 0.365, surfactant slug 0.365 meq/ml salinity, cushion slug of 0.365 meq/ml salinity, and then polymer and water drive of 0.335 meq/ml salinity.
FIG. 1 is a graphical summary of the results of the simulations with a negative salinity gradient as compared with an optimum salinity profile. Comparing the recovery factors of the negative salinity gradient system with the recovery factors for the optimum salinity profile system, as shown in FIG. 1, in every simulation, the optimum salinity profile provides a higher oil recovery factor. On average, there is a 12.3% higher recovery factor with the optimum salinity profile system as compared to the negative salinity gradient system.
FIG. 2 is a schematic detailing one embodiment of an optimum salinity profile. On the x-axis is the injection pore volume. A pore volume is the total volume of a porous medium minus the material of the rock. In other words, a pore volume is the total volume of a fluid, say oil, required to saturate the porous medium. The y-axis reflects the salinity of the different slugs injected into the reservoir.
Slug 201, such as preflush water, is the first slug that is injected into the reservoir. It should be noted that, according to embodiments, an important concept of this optimum salinity profile includes the salinity from formation water to post-flush water. Thus, after determining the optimum salinity of the surfactant slug 203, this optimum salinity of the surfactant slug is used to set the salinity of each salinity cushion slug which provides cushions for the surfactant slug 203. This novel approach in setting salinities of all the slugs to provide a cushion for the surfactant slug 203 is disclosed herein, as an optimum salinity profile. The salinity of slug 201 may be of any salinity. In some instances, the salinity selected for slug 201 will be determined with reference to the salinity of the formation water. Following the injection of the preflush water, the first slug cushion 202 is injected. It should be noted that a cushion slug may be fluids such as water, brine or polymer mobility-control solution. Cushion 202 will have the same salinity as the surfactant slug 203. It should be noted that the surfactant slug 203 may be a surfactant/polymer slug or a surfactant slug without polymer. In some embodiments, the polymer is a mobility control agent. Surfactant slug 203 preferably has an actual optimum salinity as determined by a method as disclosed in co-pending application Ser. No. ______ DETERMINATION OF AN ACTUAL OPTIMUM SALINITY AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION FOR ENHANCED OIL RECOVERY. Surfactant slug 203 of the actual optimum salinity is then injected.
After the injection of surfactant slug 203, a second cushion slug 204 is injected. The second salinity cushion slug has the same salinity as the surfactant slug 203. As can be seen in FIG. 2, surfactant slug 203 is “sandwiched” between cushion slugs 202 and 204. The salinity cushions help to maintain the properties of surfactant slug 203 as slug 203 proceeds through the reservoir. It should be noted that varying the cushion slugs' salinity slightly so that the salinity of the cushion slugs are not exactly the same as the surfactant slug salinity would not take such a system variation outside the scope of this invention. Accordingly, when reference is made to about the surfactant slug salinity or about the optimum salinity, this means salinities close to the respective surfactant slug salinity or the optimum salinity that would not significantly affect the oil recovery factor.
With cushion slugs of the same or about the same as the surfactant slug, there will not be diffusion from or to slug 203, as it progresses through the reservoir, to cause slug 203's salinity to change from what it was when it was first injected. Rather, if there is diffusion, that diffusion occurs on the outer bounds of the cushion slug (front of cushion slug 202 and at the rear of cushion slug 204). Because the salinity of slug 203 is maintained at an optimum level, the performance of the slug is always at its best. After cushion slug 204 has been injected in the reservoir, slug 205 is injected in the reservoir. Slug 205 has a salinity that is lower than the salinity of slug 203. Preferably, slug 205 would have a salinity that is lower than C_sel(the lowest Type III salinity). Using this optimum salinity profile, as mentioned above, should increase oil recovery factors by about 12.3% over the widely used negative salinity gradient method. It should be noted that depending on the reservoir, one embodiment of the invention may not include slugs 201 and/or 205.
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification. As one of ordinary skill in the art will readily appreciate from the disclosure of the present invention, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present invention. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.

Claims

1. A method of recovering oil from a reservoir using surfactant flooding, said method comprising:

injecting a fluid slug in said reservoir;

injecting, after said first injection, a first cushion slug in said reservoir,

injecting a surfactant slug following said first cushion slug;

injecting a second cushion slug following said surfactant slug, wherein said first and second cushion slugs have salinities selected from the list consisting of: the salinity of said surfactant slug and about the salinity of said surfactant slug; and

injecting a fluid slug of lower salinity than said surfactant slug, after said second cushion slug, wherein said injected fluid slug, of lower salinity than said surfactant slug, has a salinity lower than the lowest salinity at which a three phase microemulsion system exists at equilibrium.

2. The method of claim 1 wherein said salinities of said first and second cushion slugs are the same as said surfactant slug.

3. The method of claim 1 wherein said surfactant slug contains a co-surfactant.

4. The method of claim 1 wherein said surfactant slug includes a polymer.

5. The method of claim 1 wherein said first and second cushion slugs are selected from the list consisting of:

water, brine and mobility control agents.

6. (canceled)

7. The method of claim 1 wherein said first injected fluid slug is selected from the list consisting of:

water, brine and mobility control agents.

8. The method of claim 1 wherein said first injected fluid slug has a salinity different from said surfactant slug.

9. (canceled)

10. (canceled)

11. The method of claim 1 further comprising:

injecting a fluid slug of lower salinity than said surfactant slug, after said second cushion slug.

12. The method of claim 11 wherein said fluid slug is selected from the list comprising:

water, brine and surfactant solution mobility control agents.

13. The method of claim 1 wherein the salinity of said surfactant slug is an actual optimum salinity determined by running experiments, wherein said actual optimum salinity determined from said experiments is a function of IFT and parameters other than IFT.

14. The method of claim 13 wherein said experiments include running core flood experiments.

15. The method of claim 14 wherein said core flood experiments are run first to determine the actual optimum system type and then to determine an actual optimum salinity in said actual optimum system type.

16. The method of claim 14 wherein said core flood experiments are run in at least two surfactant system types, said surfactant system types selected from the list consisting of: Type II(−), Type III, and Type II(+) system.

17. A method of recovering oil from a reservoir, said method comprising:

selecting an optimum salinity by running at least one core flood experiment to measure oil recovery applicable to each of at least two surfactant system types, said surfactant system types selected from the list consisting of: Type II(−), Type III, and Type II(+) system;

injecting a first cushion slug in said reservoir,

then injecting a surfactant slug; and

then injecting a second cushion slug, wherein said first and second cushion slugs and said surfactant slug is or about at the optimum salinity.

18. The method of claim 17 further comprising:

injecting a fluid slug prior to said first cushion slug.

19. The method of claim 17 further comprising:

injecting a fluid slug of lower salinity than said optimum salinity, after said second cushion slug.

20. The method of claim 17 wherein said first and second cushion slugs are selected from the list consisting of:

water, brine and mobility control agents.

21. A method of recovering oil from a reservoir using surfactant flooding, said method comprising:

injecting a fluid slug in said reservoir;

injecting a first cushion slug;

injecting a surfactant slug following said first cushion slug, said surfactant slug comprising a polymer and a co-surfactant;

injecting a second cushion slug following said surfactant slug, wherein said first and second cushion slugs comprise brine and a mobility control agent and said first and second cushion slugs have salinities selected from the list consisting of: the salinity of said surfactant slug and about the salinity of said surfactant slug; and

22. The method of claim 21 wherein said surfactant salinity is an actual optimum salinity determined by running experiments and said actual optimum salinity determined from said experiments is a function of IFT and parameters other than IFT.

23. The method of claim 22 wherein said experiments include running core flood experiments.

24. The method of claim 23 wherein said core flood experiments are run first to determine the actual optimum system type and then to determine an actual optimum salinity in said actual optimum system type.

25. The method of claim 14 wherein said core flood experiments are run in all of the following surfactant system types: Type II(−), Type III, and Type II(+) system.