US20140262275A1

US20140262275A1 - Alkali polymer surfactant sandwich

Info

Publication number: US20140262275A1
Application number: US13/835,030
Authority: US
Inventors: Robert Matthew Dean; Dustin L. Walker; Will S. Slaughter; Taimur Malik; Varadarajan Dwarakanath
Original assignee: Chevron USA Inc
Current assignee: Chevron USA Inc
Priority date: 2013-03-15
Filing date: 2013-03-15
Publication date: 2014-09-18
Also published as: WO2014149824A1

Abstract

Aspects of the invention relate to methods for enhancing the amount of oil recovered from subterranean reservoirs or reducing the amount of surfactant needed. The method includes injecting a first alkali-polymer slug through a wellbore into a reservoir, followed by injecting a alkali-polymer-surfactant slug through the wellbore into the reservoir, and then injecting a second alkali-polymer slug through the wellbore into the reservoir.

Description

TECHNICAL FIELD

The present disclosure generally relates to a method for chemically enhanced oil recovery. In particular cases, the present disclosure concerns a method of injecting an alkali-polymer (AP) mixture into a reservoir before and after injecting an alkali-surfactant-polymer (ASP) mixture in order to control loss of surfactant performance due to cation exchange, increase polymer stability at high temperatures, enhance recovery of oil and/or to reduce the amount of surfactant needed.

BACKGROUND

Reservoir systems, such as petroleum reservoirs, typically contain fluids such as water and a mixture of hydrocarbons such as oil and gas. To remove (“produce”) the hydrocarbons from the reservoir, different mechanisms can be utilized such as primary, secondary or tertiary recovery processes.
In a primary recovery process, hydrocarbons are displaced from a reservoir through the high natural differential pressure between the reservoir and the bottomhole pressure within a wellbore. The reservoir's energy and natural forces drive the hydrocarbons contained in the reservoir into the production well and up to the surface. Artificial lift systems, such as sucker rod pumps, electrical submersible pumps or gas-lift systems, are often implemented in the primary production stage to reduce the bottomhole pressure within the well. Such systems increase the differential pressure between the reservoir and the wellbore intake; thus, increasing hydrocarbon production. However, even with use of such artificial lift systems only a small fraction of the original-oil-in-place (OOIP) is typically recovered using primary recovery processes as the reservoir pressure, and the differential pressure between the reservoir and the wellbore intake declines overtime due to production. For example, typically only about 10-20% of the OOIP can be produced before primary recovery reaches its limit, either when the reservoir pressure is so low that the production rates are not economical or when the proportions of gas or water in the production stream are too high.
In order to increase the production life of the reservoir, secondary or tertiary recovery processes can be used. Secondary recovery processes include water or gas well injection, while tertiary methods are based on injecting additional chemical compounds into the well. Typically in these processes, fluids are injected into the reservoir to maintain reservoir pressure and drive the hydrocarbons to producing wells. An additional 10-50% of OOIP can be produced in addition to the oil produced during primary recovery. While secondary and tertiary methods of oil recovery can further enhance oil production from a reservoir, care must be taken in choosing the right processes and injection fluid for each reservoir, as some methods may cause formation damage or plugging.
A well-known tertiary recovery process is alkali-surfactant-polymer (ASP) flooding. Polymers are used to increase the viscosity of a fluid, thereby leading to a reduced mobility ratio and to improved sweep efficiency. The most commonly used polymer for surfactant-polymer flooding is polyacrylamide (PAM) in its anionic form, hydrolyzed polyacrylamide (HPAM). Surfactants are used to lower the interfacial properties of the reservoir, thereby reducing capillary forces and increasing the efficiency of the displacement of oil. A wide variety of surfactants exist, but the most widely used in prior literature are petroleum sulfonates. Recent work has focused on use of synthetic surfactants, which are typically higher cost, thereby requiring means to reduce adsorption and retention. Alkali is used to raise the pH of the flood, minimizing the amount of surfactant adsorbed. The compositions of chemicals used in enhanced oil recovery (EOR) processes may vary depending on the type, environment, and composition of the reservoir formation.
Many factors affect the choice of surfactant for use in a specific reservoir. For example, the salinity of the water in subterranean hydrocarbon reservoirs can vary a great deal, as can the pH. For example, one oil field has total dissolved salts of between 0.2 and 0.3 weight percent. Other reservoirs may have salinities as high as 20 percent total dissolved solids and over 0.5 percent divalent in the form of calcium and magnesium ions (or higher). Currently, it is desirable to optimize the surfactant used in an ASP flood by evaluating tailored versions of the surfactants with native reservoir brine and reservoir oil under subterranean reservoir conditions via phase behavior experiments.
In the enhanced oil recovery process, the addition of surfactants, polymers, co-solvents and electrolytes improve the oil recovery significantly. However, surfactant adsorption is one of the main causes of high chemical cost during chemical flood. If the surfactant mass required to propagate through a reservoir can be reduced, then the cost associated with the surfactant is also reduced. Alkali is one such means to ensure low surfactant adsorption/retention.

SUMMARY

A general embodiment of the disclosure is a method for enhancing oil recovery in a subsurface reservoir in fluid communication with a wellbore comprising injecting a first alkali-polymer slug through the wellbore into the reservoir; injecting an alkali-polymer-surfactant slug through the wellbore into the reservoir; and injecting a second alkali-polymer slug through the wellbore into the reservoir. The method may further comprise injecting a polymer slug through the wellbore into the reservoir following the second alkali-polymer slug. In specific embodiments, the first and second alkali-polymer slugs comprise about the same amounts of alkali and/or polymer or different amounts of polymer and/or alkali. The alkali-polymer-surfactant slug may comprise less surfactant mass than a predetermined optimal surfactant amount. For example, the alkali-polymer-surfactant slug may comprise greater than 95%, greater than 90%, greater than 80%, greater than 70%, greater than 60%, or greater than 50%, of the predetermined optimal surfactant amount. In some embodiment, the alkali-polymer-surfactant slug comprises between 50-80% of the predetermined optimal surfactant amount, or between 40-60% of the optimal surfactant amount while still achieving greater than 90% residual oil recovery.
In specific embodiments, the alkali-polymer-surfactant slug comprises one or more of the group consisting of internal olefin sulfonates, isomerized olefin sulfonates, alkyl aryl sulfonates, medium alcohol (C10 to C17) alkoxy sulfates, alcohol ether [alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, primary amines, secondary amines, tertiary amines, quaternary ammonium cations, cationic surfactants that are linked to a terminal sulfonate or carboxylate group, alkylaryl alkoxy alcohols, alkyl alkoxy alcohols, alkyl alkoxylated esters, and alkyl polyglycosides. In some embodiments, the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises one or more of the group consisting of sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate, sodium citrate, and sodium tetraborate. In specific embodiments, the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises one or more of the group consisting of xanthan gum, scleroglucan, partially hydrolyzed polyacrylamides, hydrophobically-modified associative polymers, co-polymers of polyacrylamide (PAM), 2-acrylamido 2-methylpropane sulfonic acid, and N-vinyl pyrrolidone (NVP). The alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug can comprise 0.1 to 5 weight percent alkali, for example, 0.3 to 3 weight percent, 0.4 to 2.5 weight percent, or 0.6 to 1.5 weight percent alkali. The alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug can comprise at least 500 ppm polymer, at least 1000 ppm polymer, at least 2000 ppm polymer, at least 3000 ppm polymer or at least 5000 ppm polymer. The alkali-polymer-surfactant slug may comprise 0.1 to 5 weight percent surfactant, for example, the slug can comprise 0.3 to 3 weight percent, or 0.5 to 2 weight percent surfactant.
The method may further comprise receiving production fluid from the reservoir. Additionally, the first and/or the second alkali-polymer slug can be optimized for the subsurface reservoir by adjusting the concentration of alkali and polymer to at least about 50%, at least about 60%, at least about 70%, at least about 80%, or at least about 90% of optimal salinity for the reservoir. In some embodiments, the alkali-surfactant-polymer slug is optimized for the subsurface reservoir by adjusting one or more of the concentration of alkali, polymer and surfactant to at least about 50%, at least about 60%, at least about 70%, at least about 80%, or at least about 90% of optimal salinity for the reservoir.
In specific embodiments, the method further comprises softening seawater or waste brine prior to injection of the first alkali-polymer, and adding alkali and polymer to the softened seawater to form the first alkali-polymer slug. In additional embodiments, seawater or waste brine is softened prior to injection of the first alkali-polymer; and alkali, polymer, and surfactant are added to the softened seawater to form the alkali-polymer-surfactant slug. The method may also comprise, softening seawater or waste brine prior to injection of the first alkali-polymer, and adding alkali and polymer to the softened seawater to form the second alkali-polymer slug.
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. It should be appreciated by those skilled in the art that the conception and specific embodiments 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 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 is an illustration of a pre-ASP AP slug entering a subterranean reservoir.

FIG. 2 is an illustration of an ASP slug entering a subterranean reservoir after a pre-ASP AP slug.

FIG. 3 is an illustration of a post-ASP AP slug entering a subterranean reservoir after a ASP slug and a pre-ASP AP slug.

FIG. 4 is a graph of oil recovered, oil cut per pore volume for an example core flood using an ASP slug and a post-ASP AP slug.

FIG. 5 is a graph of oil recovered, oil cut per pore volume for an example core flood using a pre-ASP AP slug, an ASP slug and a post-ASP AP slug.

FIG. 6 is a graph of oil recovered, oil cut per pore volume for an example core flood using a pre-ASP AP slug, an ASP slug and a post-ASP AP slug, where the ASP slug had a reduced mass of surfactant when compared to the composition used in FIG. 5.

FIG. 7 is a graph of oil recovered, oil cut per pore volume for an example core flood in a control core flood.

FIG. 8 is a graph of oil recovered, oil cut per pore volume for an example core flood with a pre-ASP AP and post-ASP AP slug.

FIG. 9 is a graph of oil recovered, oil cut per pore volume for an example core flood with no pre-ASP AP or post-ASP AP slug.

FIG. 10 is a graph of oil recovered, oil cut per pore volume for an example core flood with half the surfactant used in the core of FIG. 9 but including a pre-ASP AP slug and a post-ASP AP slug.

DETAILED DESCRIPTION

Aspects of the present invention describe a method for enhancing the oil recovery from surfactant polymer floods or for reducing the mass of surfactant needed during a surfactant polymer flood. Specifically, an embodiment comprises injecting an AP mixture before and after injecting an ASP mixture into a reservoir.
Not to be limited by theory, it is thought that alkaline environments reduce anionic surfactant absorption. In embodiments, the AP mixture injected prior to a surfactant slug successfully raises the pH and increases or maintains the effective salinity in front of the surfactant slug while protecting surfactant from hardness and limiting surfactant mobility. The AP mixture injected behind the surfactant slug maintains the effective salinity and high pH and allows the surfactant slug to stay in an optimum environment, i.e. Winsor type III region, throughout the entire flood. This process minimizes surfactant adsorption because the surfactant is always in a high pH environment, while the polymer provides mobility control. The minimized surfactant absorption and small surfactant slug size reduces the surfactant mass needed and, thus, the costs of the process. That is, the pre-ASP AP slug 1) provides mobility control of the following ASP slug 2) raises pH to lower surfactant absorption, and 3) precipitates multivalent cations that are in the mixing zone, thus further protecting the ASP slug. The post-ASP AP slug 1) provides mobility control behind the ASP slug and 2) keeps the ASP slug at optimal salinity (lowest oil-water interfacial tension) and high pH (optimal phase behavior; protects some anionic surfactants (sulfates) at high temperature) and 3) protects the polymer in a softened water environment with high pH
As used herein, the term “equal” refers to equal values or values within the standard of error of measuring such values. The term “substantially equal” or “about” refers to an amount that is within 3% of the value recited.
As used herein, “a” or “an” means “at least one” or “one or more” unless otherwise indicated.
As used herein, a “polymer sandwich” refers to a sequence of injected slugs, first starting with an AP composition that does not comprise an effective amount of surfactant, followed by an ASP composition, and followed by an AP composition that does not comprise an effective amount of surfactant.
“Optimal salinity” is the salinity which recovers the highest amount of oil. Optimal salinity can be measured by performing a salinity scan (phase behavior test) with alkali on a mixture of an injection water, crude oil, and surfactant; where the point at which equal volumes of crude oil and water are solubilized is defined as the optimal salinity. Alkali concentration at optimal salinity is different for every crude/surfactant combination (see examples in FIGS. 4 to 6). In embodiments, the alkali in the AP or ASP slugs provides, contributes, or maintains the salinity. For highest oil recovery, it is desirable to maintain optimal salinity over the longest duration in the subsurface.
“High pH” is a pH which successfully reduces the amount of surfactant adsorbed by a reservoir and maintains the surfactant in an environment which results in low interfacial tension. In some embodiments, “High pH” is between about 8 to 14, between about 9 to 12, or >8 pH.
“Effective amount,” when used in reference to surfactant, refers to an amount sufficient to affect an increase in oil recovery over not including the component. For example, an effective amount of surfactant in an ASP slug would increase oil recovery over only using the equivalent AP slug without surfactant.
“Pore volume” or “PV” fraction as used herein refers to the total volume of pore space in the oil reservoir that is contemplated in a sweep (contacted pore space at ASP, AP, PD mobility ratio).
FIG. 1 is an example oil recovery system which includes injection well 11 which extends to a portion of a subsurface reservoir 13 containing hydrocarbons for production, such that injection well 11 is in fluid communication with subsurface reservoir 13 and the hydrocarbons. Production well 15 is also in fluid communication with reservoir 13 in order to receive the hydrocarbons. Production well 15 is positioned a lateral distance away from injection well 11. For example, production well 15 can be positioned between 50 feet to 10,000 feet away from injection well 11. There can be additional production wells (not shown) at predetermined locations to optimally receive the hydrocarbons being pushed through reservoir 13 due to injections from additional injection wells (not shown).
In an embodiment, as illustrated in FIG. 1, a first AP slug 17 is injected through the injection well 11 into reservoir 13. The first AP slug 17 may be preceded by a pre-flush, such as a pre-flush of softened water at any desired salinity. As described further below, the AP slug comprises alkali and polymer. The first AP slug 17 disperses through reservoir 13, with at least a portion thereof proceeding toward production well 15.
Following the injection of the first AP slug 17, an ASP slug 21 is injected in to the reservoir, as shown in FIG. 2. The trailing edge of the first AP slug 17 keeps the leading edge of the ASP slug 21 around optimal salinity and around optimal pH. The ASP slug 21 is then followed by the second AP slug 31, as shown in FIG. 3. The leading edge of the second AP slug 31 keeps the trailing edge of the ASP slug 21 at around optimal salinity and around optimal pH.
A driver or chaser slug, “polymer drive” may be injected through the injection well into the reservoir after the second AP slug 31 or the second AP slug 31 may function as the polymer drive where desired. The polymer used in the chaser slug can be the same polymer used in slugs 17, 21, or 31, or may be different. In one embodiment, multiple chaser slugs can be injected. For example, a first chaser slug containing a small amount of polymer can be injected and the followed by a second chaser slug containing a larger amount of polymer.
The methods of the disclosure may be performed on-shore or off-shore, and may be adjusted to make the most efficient use of the location. As an example, seawater may be used as an aqueous base for any of the slugs described here, since off-shore production facilities tend to have an abundance of seawater available, limited storage space, and transportation costs to and from off-shore site are typically high. If seawater is used as the aqueous base, it is usually softened prior to the addition of the alkali, polymer and/or surfactant, thereby removing any multivalent ions, specifically Mg and Ca, as they can precipitate and cause injection problems. Additionally, the alkali, polymer, and surfactants may be added to an aqueous base fluid in a solid form or in a solution. Solid forms may be put into solution prior to addition to the production fluid or the solid form may be directly added to the production fluid.
Embodiments of the disclosure are practiced in high temperature reservoirs, for example, greater than 50° C., greater than 55° C., greater than 60° C., greater than 65° C., greater than 70° C., greater than 80° C., or greater than 90° C. In some embodiments, the temperature of the reservoir is 15° C. to over 100° C.
Pre-ASP and Post-ASP AP Slug
As discussed in reference to FIGS. 1 and 3, in one embodiment AP slugs 17 and 31 used in flooding processes for enhanced oil recovery in reservoirs comprise effective amounts of alkali and polymer in an aqueous solution and do not compromise an effective amount of a surfactant. The alkali and polymer used in the first AP slug 17 and the second AP slug 31 may be the same or different. Additionally, the alkali and polymers may be compositions comprising more than one alkali or polymer. The aqueous solution which comprises the alkali and polymer can be a softened brine with a lower TDS than necessary for “Optimal Salinity” (because of the desire to add an alkali to achieve “Optimal” or near “Optimal Salinity”). For example, the aqueous solution comprises from about 100 to about 150,000 ppm total dissolved solids. The experiments in FIGS. 4 to 6 have a softened water source of 3000 ppm TDS. The dissolved solid may be NaCl, or KCl, or any combination of other monovalent salts. The optimal composition of the AP solution will vary based on the nature of the oil that is being recovered, the nature of reservoir that it is being recovered from, and the nature of the surfactant composition used in the ASP slug 21.
For each reservoir operation, an optimal salinity can be determined, and the AP slugs 17 and 31 can be mixed in order to achieve the optimal salinity. Such methods for achieving optimal salinity are described and taught by “Identification and Evaluation of High-Performance EOR Surfactants,” D. B. Levitt, A. C. Jackson, C. Heinson, L. N. Britton, T. Malik, V. Dwarakanath, and G. A. Pope, SPE/DOE Symposium on Improved Oil Recovery (SPE 100089), 22-26 Apr. 2006, Tulsa, Okla., USA, 2006. The formulation of the first AP slug 17 is typically responsive to the amount of electrolytes associated with the reservoir and/or the water (mixing with produced water or fresh). For a low salinity field where a non-negative salinity gradient (“The Effect of a Non-Negative Salinity Gradient on ASP Flood Performance” Levitt, D. B; Chamerois, M.; Bourrel, M., Gauer, P.; Morel, D. SPE 144938, Presented at the SPE Enhanced Oil Recovery Conference, Kuala Lumpur, Malaysia, 19-21 Jul. 2011) may be employed, AP slug 17 generally is some optimized proportion of “Optimal Salinity.” For example, in the experiments of FIGS. 5 and 6, background formation brine salinity was 3000 ppm hard brine, AP slug was injected at 7400 ppm alkali (Na₂CO₃). This alkali concentration is 80% optimal salinity. The extra mass of alkali not only functions to reduce surfactant adsorption via high pH and remove multivalent cation interactions with the surfactant, but also aids in maintaining an optimal salinity environment throughout the entire flood.
As used herein, an “alkali-polymer slug,” “pre-ASP Aslug,” “post-ASP Aslug,” or “Aslug” refers to a slug which comprises both alkali and polymer. The AP slug does not comprise an effective amount of surfactant, but does comprise effective amounts of alkali, and effective amounts of polymer. Effective amounts of alkali are concentrations of alkali that help maintain a high pH and desired salinity of the ASP slug 21. In one example, the effective amounts of alkali are within 20%, are within 10%, are within 5%, are within 3% or are equal to the optimal levels of salinity and pH determined for a specific reservoir operation. For example, effective amounts of alkali could include, but are not limited to about 0.5% to 10%, 0.5% to 5%, or greater than the minimum effective propagation concentration (“Selection and Evaluation of Surfactants for Field Pilots,” Dean, R. M., M. S. Thesis 2011. University of Texas at Austin, Austin, Tex.).
Effective amounts of polymer are concentrations that allow the slug to efficiently sweep the reservoir. The required viscosity is a function of mobility ratio. Mobility ratio (M) is defined as water (or ASP) relative permeability divided by oil relative permeability multiplied by oil viscosity divided by water (or ASP) viscosity (krw/kro*μo/μw). Generally a unit mobility ratio, M=1, or lower is desired in an ASP flood. In one example, effective amounts of polymer are equal to or less than that of each subsequent slug's viscosity in order obtain favorable mobility ratio throughout the entire flood process. For example, effective amounts of polymer include, but are not limited to about 250 ppm to about 5,000 ppm, such as about 500 to about 2500 ppm concentration, or about 750 to 3000 ppm in order to achieve a favorable mobility ratio under the reservoir conditions of temperature. Additionally, in some embodiments, the pre-ASP AP slug and the post-ASP AP slug comprise about the same or different amounts of alkali. In other embodiments, the pre-ASP AP slug and the post-ASP AP slug comprise the same or different amounts of polymer.
For each reservoir operation, the optimal slug volume for either or both AP slugs 17 and 31 may be determined. For example, the AP slugs may be injected into the reservoir in volumes of between 0.05 to 0.5 PV, 0.1 to 0.4 PV, or ˜0.1 PV. The necessary slug size can be determined through core flooding experiments and simulation. The volume of first AP slug 17 may be the equal to, or different from the volume of the second AP slug 31. The speed of injection of the slugs may also vary depending on the reservoir operations.
ASP Slug
As discussed in reference to FIG. 2, ASP slug 21 used in flooding techniques for enhanced oil recovery in reservoirs comprises an alkali, a surfactant, and a polymer in an aqueous solution. The alkali and polymer used may be the same or different from the alkali and polymers used in the first and second AP slugs 17 and 31. Additionally, the alkali, surfactant and polymers may be compositions comprising more than one alkali, surfactant or polymer. In one embodiment, the aqueous solution comprises from about 500 to about 10,000 ppm total dissolved solids, such about 2,000 to about 8,000 ppm, about 1,000 ppm to about 5,000 ppm, or about 5,000 to about 9,500 ppm. The dissolved solid may be monovalent cations and their corresponding anions in the softened brine and additional alkali to achieve the predetermined optimal salinity. The optimal composition of the ASP solution will vary based on the nature of the oil that is being recovered and the nature of reservoir that it is being recovered from.
As discussed above for the AP slugs, for each reservoir operation, an optimal salinity and pH can be determined. The ASP slug 21 can be mixed in order to achieve the optimal salinity and pH. Such methods for achieving optimal salinity are described and taught by “Identification and Evaluation of High-Performance EOR Surfactants,” D. B. Levitt, A. C. Jackson, C. Heinson, L. N. Britton, T. Malik, V. Dwarakanath, and G. A. Pope, SPE Reservoir Evaluation & Engineering (SPE 100089-PA-P), April 2009, p. 243-253. In an embodiment, the ASP solution may have a salt tolerance of at least greater than the optimal salinity at reservoir temperature while still recovering greater than 90 percent of the residual oil.
Additionally, an optimal amount of surfactant can be predetermined. The optimal surfactant amount in a coreflood is the minimum amount of surfactant that recovers >90% residual oil additional oil with the lowest mass of surfactant. The predetermined optimal surfactant formulation (surfactant, co-surfactant, co-solvent, optimal salinity) is determined by lab phase behavior measurements (see Levitt 2009 for method). The predetermined optimal surfactant amount is calculated without taking into account the additional pre-ASP and post-ASP AP slugs. This predetermined optimal surfactant amount is considered the “normal” mass of surfactant one would add to a conventional ASP slug. In an embodiment, with the use of the pre-ASP and post-ASP AP slugs, a lower mass of surfactant may be used than the normal amount.
As used herein, an “alkali-surfactant-polymer slug” or “ASP slug” refers to a slug which comprises alkali, polymer and surfactant. Effective amounts of alkali are concentrations of alkali that help maintain the pH and salinity of the ASP slug 21. In one example, the effective amounts of alkali are within 30%, within 20%, within 10%, within 5%, within 3% or are equal to the optimal levels of salinity determined for a specific reservoir operation. For example, effective amounts of alkali could include any concentration greater than the minimum amount required to propagate pH through the reservoir, which is dependent upon salinity, hardness, clay content, CEC, and Temperature (Dean, 2011), all the way to as high as the concentration required in the ASP slug. Effective amounts of polymer are concentrations that allow the slug to efficiently sweep the reservoir. Viscosity at a given concentration is dependent on salinity, therefore viscosity must be compared when slugs have differing concentrations of alkali. In one example, effective viscosities of polymer are within 20%, within 10%, within 5%, within 3% or are equal to the optimal levels of viscosity determined for a specific reservoir operation. For example, effective amounts of polymer include, but are not limited to about 250 ppm to about 5,000 ppm, such as about 500 to about 4000 ppm concentration, or about 1000 to 4000 ppm in order to match or exceed the reservoir oil viscosity under the reservoir conditions of temperature and pressure.
Effective amounts of surfactant are concentrations which can be propagated at a velocity within 25% to that of the polymer and alkali and are well above the critical micelle concentration (CMC) and/or increases the amount of oil recovered from a reservoir. For example, effective amounts of surfactant could include, but are not limited to about 0.1 to 5.0% by weight, or about 0.3% to 3% by weight. In one embodiment, the surfactant mass used is within about 1 wt % *0.30 PV; i.e. 2 wt % *0.15 PV; 0.5 wt %*0.6 PV, or about 1 wt % *0.25 PV. The slug size is dependent upon the concentration used. Optimized total mass tries to be equal to the total estimated amount of surfactant that will adsorb or be retained in the reservoir.
The volume of the ASP slug 21 may be the equal to, or different from the volumes of the first and second AP slugs 17 and 31. The speed of injection of the slugs may also vary depending on the reservoir operations.
Polymer
Water soluble polymers, such as those commonly employed for enhanced oil recovery, are included to control the mobility of the injection solution. Such polymers include, but are not limited to, biopolymers such as xanthan gum and scleroglucan and synthetic polymers such as partially hydrolyzed polyacrylamides (HPAMs or PHPAs) and hydrophobically-modified associative polymers (APs). Also included are co-polymers of polyacrylamide (PAM) and one or both of 2-acrylamido 2-methylpropane sulfonic acid (and/or sodium salt) commonly referred to as AMPS (also more generally known as acrylamido tertiobutyl sulfonic acid or ATBS) and N-vinyl pyrrolidone (NVP). Molecular weights (Mw) of the polymers range from about 100,000 Daltons to about 30,000,000 Daltons, such as about 100,000 to about 500,000, or about 1,000,000 to about 20,000,000 Daltons. In specific embodiments of the invention the polymer is about 2,000,000 Daltons, about 8,000,000 Daltons, or about 20,000,000 Daltons. The polymer and the size of the polymer may be tailored to the permeability, temperature and salinity of the reservoir.
Surfactant
Surfactants are included to lower the interfacial tension between the oil and water phase to less than about 10̂−2 dyne/cm (for example) and thereby recover additional oil by mobilizing and solubilizing oil trapped by capillary forces. Examples of surfactants that can be utilized include, but are not limited to, anionic surfactants, cationic surfactants, amphoteric surfactants, non-ionic surfactants, or a combination thereof. Anionic surfactants can include sulfates, sulfonates, phosphates, or carboxylates. Such anionic surfactants are known and described in the art in, for example, U.S. Pat. No. 7,770,641, incorporated herein in full. Examples of specific anionic surfactants include internal olefin sulfonates, isomerized olefin sulfonates, alkyl aryl sulfonates, medium alcohol (C10 to C17) alkoxy sulfates, alcohol ether [alkoxy]carboxylates, and alcohol ether [alkoxy]sulfates. Example cationic surfactants include primary, secondary, or tertiary amines, or quaternary ammonium cations. Example amphoteric surfactants include cationic surfactants that are linked to a terminal sulfonate or carboxylate group. Example non-ionic surfactants include alcohol alkoxylates such as alkylaryl alkoxy alcohols or alkyl alkoxy alcohols. Other non-ionic surfactants can include alkyl alkoxylated esters and alkyl polyglycosides. In some embodiments, multiple non-ionic surfactants such as non-ionic alcohols or non-ionic esters are combined. As a skilled artisan may appreciate, the surfactant(s) selection may vary depending upon such factors as salinity, temperature, and clay content in the reservoir. The surfactants can be injected in any manner such as continuously or in a batch process.
Alkali
The alkali employed is a basic salt of an alkali metal from Group IA metals of the Periodic Table. In an embodiment, the alkali metal salt is a base, such as an alkali metal hydroxide, carbonate or bicarbonate, including, but not limited to, sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate, sodium citrate, and sodium tetraborate. The alkali is typically used in amounts ranging from about 0.3 to about 5.0 weight percent of the solution, such as about 0.5 to about 3 weight percent. As previously discussed, use of the alkali maintains surfactant in a high pH environment, thereby minimizing surfactant adsorption. Alkali also protects the surfactant from hardness. Using alkali before and after the ASP slug helps to minimize surfactant adsorption, as a high pH environment is maintained through any diffusion of the ASP slug.
Additional Additives
The slugs described throughout this disclosure, including the AP slugs 17 and 31, the ASP slug 21, and any chaser slugs can also include additional additives. These additives include chelators, co-solvents, reducing agents/oxygen scavengers, and biocides. Chelators may be used to complex with multivalent cations and soften the water in the solution. Examples of chelators include ethylenediaminetetraacetic acid (EDTA) which can also be used as an alkali, methylglycinediacetic acid (MGDA). Chelants may be utilized to handle hard brines. The amount of chelant may be selected based on the amount of divalent ions in the slug solutions. For example, chelating agents can be used a 10:1 molar ratio with divalent cations such as calcium or magnesium. Other chelating agents may work depending on the brine composition and the desired pH.
Co-solvents may also be included in the slug compositions. Suitable co-solvents are alcohols, such as lower carbon chain alcohols like isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol and the like; alcohol ethers, polyalkylene alcohol ethers, polyalkylene glycols, poly(oxyalkylene)glycols, poly(oxyalkylene)glycols ethers or any other common organic co-solvent or combinations of any two or more co-solvents. For example, in an embodiment, an ether, ethylene glycol butyl ether (EGBE), is used and typically is about 0.75 to 1.5 times the concentration of surfactant of ASP slug 21. Generally, the co-solvent when used may be present in an amount of about 0.5 to about 6.0 weight percent of the solution, such as from about 0.5 to about 4.0 weight percent, or about 0.5 to about 3 weight percent.
Reducing agents/oxygen scavengers such as sodium dithionite may be used to remove any oxygen in the mixture and reduce any free iron into Fe²⁺. They are used to protect synthetic polymers from reactions that cleave the polymer molecule and lower or remove viscosifying abilities. A reduced environment also lowers surfactant adsorption.
Biocides are used to prevent organic (algal) growth in facilities, stop sulfate reducing bacteria (SRB) growth which “sour” the reservoir by producing dangerous and deadly H₂S, and are also used to protect biopolymers from biological life which feed on their sugar-like structures and therefore remove mobility control. Biocides include aldehydes and quaternary ammonium compounds.

EXAMPLES

The following examples are included to demonstrate specific embodiments of the disclosure. It should be appreciated by those of skill in the art that the techniques disclosed in the examples that follow represent techniques discovered by the inventors to function well in the practice of the invention, and thus, can be considered to constitute modes for its practice. However, those skilled in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments disclosed and still obtain a like or similar result without departing from the scope of the invention.

Example 1

Core Floods

Core flood experiments were conducted according to known laboratory methods for reservoir cores where the reservoir salinity was less than the optimal salinity for an ASP slug. In this example, five core floods were run using a brine flood core. The core was first oil flooded to initial oil saturation levels (S_oi), after which they were water flooded to residual oil saturation (S_orw). Note, S_oiand S_orwwill be specific to a particular reservoir. The four core floods proceeded as follows:
Flood #1: post-ASP AP slug only in Reservoir Core

- Injected an ASP slug with a normal mass of S.
- Injected an AP slug (post-ASP AP slug).
- Injected a P slug (Polymer Drive).

Flood #2: pre and post-ASP AP slug in Reservoir Core

- Injected an AP slug (pre-ASP AP slug).
- Injected an ASP slug in core floods with a normal mass of S.
- Injected an AP slug (post-ASP AP slug).
- Injected a P slug (Polymer Drive).

Flood #3: pre and post-ASP AP slugs with lower S in Reservoir Core

- Injected an AP slug (pre-ASP AP slug).
- Injected an ASP slug in core floods with a lower mass of S than required
- Injected an AP slug (post-ASP AP slug).
- Injected a P slug (Polymer Drive).

Flood #4: control in Surrogate Core

- Inject an ASP slug in core floods with a normal mass of S.
- Injected a P slug (Polymer Drive).

Flood #5: pre and post-ASP AP slug in Surrogate Core

A summary of the floods follows in Table 1. The polymer was an AMPS polymer manufactured by SNF. The brine was a softened version of the 3000 ppm formation brine. The surfactant blend was a mixture of anionic sulfonate surfactants. The co-solvent was EGBE.

TABLE 1

Summary of floods 1-5.

Composition	Flood	1	Flood 2	Flood 3	Flood 4	Flood 5

Slug 1	Polymer	—	2750 ppm	2750 ppm	—	2750 ppm
(pre-	Brine	—	3000 ppm	3000 ppm	—	3000 ppm
ASP AP)			NaCl	NaCl		NaCl
	Na₂CO₃	—	0.72% (80%	0.72% (80%	—	0.72%
			S*)	S*)		(80% S*)
	Volume	—	0.10 PV	0.15 PV	—	0.15 PV
	Viscosity	—	10.5 cP	10.5 cP	—	10.5 cP
Slug
2	Surfactant	1.50%	1.50%	1.50%	1.50%	1.50%
(ASP)	Co.	0.50%	0.50%	0.50%	0.50%	0.50%
	Surfactant
	Co-	2.80%	2.80%	2.80%	2.80%	2.80%
	solvent
	Polymer	3500 ppm	3500 ppm	2750 ppm	3600* ppm	2750 ppm
	Brine	3000 ppm	3000 ppm	3000 ppm	3000 ppm	3000 ppm
		NaCl	NaCl	NaCl	NaCl	NaCl
	Na₂CO₃	0.90%	0.90%	0.90%	0.90%	0.90%
	Volume	0.15 PV	0.15 PV	0.10 PV	0.15 PV	0.10 PV
	Viscosity	10.5 cP	10.5 cP	6.5 cP	17 cP	6.5 cP
Slug 3	Co-	1.50%	1.50%	1.50%	—	1.50%
(post-	solvent
ASP AP)	Polymer	3500 ppm	3200 ppm	2750 ppm	—	2750 ppm
	Brine	3000 ppm	3000 ppm	3000 ppm	—	3000 ppm
		NaCl	NaCl	NaCl		NaCl
	Na₂CO₃	0.72% (85%	0.72% (80%	0.72% (80%	—	0.72%
		S*)	S*)	S*)		(80% S*)
	Volume	0.10 PV	0.10 PV	0.10 PV	—	0.10 PV
	Viscosity	11.5 cP	10.5 cP	8.5 cP	—	8.5 cP
Slug 4	Polymer	2000 ppm	2000 ppm	2000 ppm	2000 ppm	2000 ppm
(Polymer	Brine	3000 ppm	3000 ppm	3000 ppm	3000 ppm	3000 ppm
Drive)		NaCl	NaCl	NaCl	NaCl	NaCl
	Volume	1.75 PV	1.65 PV	1.65 PV	1.75 PV	1.65 PV
	Viscosity	13 cP	13 cP	13 cP	18 cP	13 cP
Result	Residual	84.40%	96%	91.1%	88.2%	94.9%
	Oil
	Recovery
Core		Reservoir	Reservoir	Reservoir	Bentheimer	Bentheimer

Flood 2 showed the highest oil recovery, while Flood 3 illustrates that equal or better oil recovery can be achieved with less surfactant by employing an AP sandwich. Graphs of oil recovered, oil cut per pore volume for Floods 1-5 are shown in FIGS. 4-8, respectively. This example illustrates that improved oil recovery is achieved using a pre-ASP AP slug and/or a post-ASP AP slug.

Example 2

Core Floods in Surrogate Core

In this example, two core floods were run using a brine flood core. The core was first oil flooded to initial oil saturation levels (S_oi), after which they were water flooded to residual oil saturation (S_orw). Note, S_oiand S_orwwill be specific to a particular reservoir. The two core floods proceeded as follows:
Flood #6: control in Surrogate Core

Flood #7: pre and post-ASP AP slug in Surrogate Core

- Injected an AP slug (pre-ASP AP slug).
- Injected an ASP slug in core floods with half the mass of surfactant than Flood #6.
- Injected an AP slug (post-ASP AP slug).
- Injected a P slug (Polymer Drive).

A summary Floods 6 and 7 is found in Table 2. The polymer was an AMPS polymer manufactured by SNF. The brine was a softened version of the 30,000 ppm formation brine. The surfactant blend was a mixture of anionic sulfonate surfactants. The co-solvent was EGBE.

TABLE 2

Summary of floods 5 and 6.

Composition	Flood	5	Flood 6

Slug 1 (pre-ASP AP)	Polymer	—	3,000 ppm
	Brine	—	30,000 ppm NaCl
	Na₂CO₃	—	2.00%
	Volume	—	0.19PV
	Viscosity	—	16
Slug 2 (ASP)	Surfactant	2.00%	2.00%
	Co. Surfactant	—	—
	Co-solvent	3.00%	3.00%
	Polymer	3,000 ppm	3,000 ppm
	Brine	30,000 ppm NaCl	30,000 ppm NaCl
			2,000 CaCl₂
	Na₂CO₃	1.75%	2.00%
	Volume	0.30 PV	0.15 PV
	Viscosity
	16	16
Slug 3 (post-ASP AP)	Co-solvent	—	—
	Polymer	—	3,200 ppm
	Brine	—	30,000 ppm NaCl
	Na₂CO₃	—	0.75%
	Volume	—	0.15 PV
	Viscosity	—	18.7
Slug 4 (Polymer Drive)	Polymer	3,200 ppm	3,200 ppm
	Brine	30,000 ppm NaCl	30,000 ppm NaCl
	Volume	1.50 PV	1.30 PV
	Viscosity	18	18
Result	Residual Oil Recovery	99.3%	91.5%
Core		Bentheimer	Bentheimer

While Flood 6 showed the highest oil recovery, Flood 7 used half the surfactant, but still recovered more than 90% of the residual oil. Graphs of oil recovered, oil cut per pore volume, and oil saturation per pore volume injected for Floods 6 and 7 are shown in FIGS. 9 and 10, respectively. This example illustrates that half the amount of surfactant can be used in conjunction with pre- and post-AP floods and still recover greater than 90% of residual oil.
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 scope of the invention as defined by the appended claims. Moreover, the scope of the present disclosure 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

What is claimed is:

1. A method for enhancing oil recovery in a subsurface reservoir in fluid communication with a wellbore comprising, in order:

injecting a first alkali-polymer slug through the wellbore into the reservoir;

injecting an alkali-polymer-surfactant slug through the wellbore into the reservoir; and

injecting a second alkali-polymer slug through the wellbore into the reservoir.

2. The method of claim 1, further comprising injecting a polymer slug through the wellbore into the reservoir following the second alkali-polymer slug.

3. The method of claim 1, wherein the alkali-polymer-surfactant slug comprises less surfactant mass than a predetermined optimal surfactant amount.

4. The method of claim 3, wherein the alkali-polymer-surfactant slug comprises the alkali-polymer-surfactant slug may comprise greater than 95%, greater than 90%, greater than 80%, greater than 70%, greater than 60%, or greater than 50%, of the predetermined optimal surfactant amount.

5. The method of claim 1, wherein the alkali-polymer-surfactant slug comprises one or more of the group consisting of internal olefin sulfonates, isomerized olefin sulfonates, alkyl aryl sulfonates, medium alcohol (C10 to C17) alkoxy sulfates, alcohol ether [alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, primary amines, secondary amines, tertiary amines, quaternary ammonium cations, cationic surfactants that are linked to a terminal sulfonate or carboxylate group, alkylaryl alkoxy alcohols, alkyl alkoxy alcohols, alkyl alkoxylated esters, and alkyl polyglycosides.

6. The method of claim 1, wherein the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises one or more of the group consisting of sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate, sodium citrate, and sodium tetraborate.

7. The method of claim 1, wherein the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises one or more of the group consisting of xanthan gum, scleroglucan, partially hydrolyzed polyacrylamides, hydrophobically-modified associative polymers, co-polymers of polyacrylamide (PAM), 2-acrylamido 2-methylpropane sulfonic acid, and N-vinyl pyrrolidone (NVP).

8. The method of claim 1, wherein the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises 0.1 to 10 percent by weight alkali.

9. The method of claim 1, wherein the alkali-polymer-surfactant slug, the first alkali-polymer slug, and/or the second alkali polymer slug comprises 250 ppm to 5,000 ppm polymer.

10. The method of claim 1, wherein the alkali-polymer-surfactant slug comprises 0.1 to 5 weight percent surfactant.

11. The method of claim 1, further comprising receiving production fluid from the reservoir.

12. The method of claim 13, wherein greater than 90% of residual oil is recovered from the reservoir.

13. The method of claim 1, wherein the first alkali-polymer slug is optimized for the subsurface reservoir by adjusting the concentration of alkali and polymer in the alkali-polymer slug to at least about 50%, at least about 60%, at least about 70%, at least about 80%, or at least about 90% of optimal salinity for the reservoir.

14. The method of claim 1, wherein the second alkali-polymer slug is optimized for the subsurface reservoir by adjusting the concentration of alkali and polymer to at least about 50%, at least about 60%, at least about 70%, at least about 80%, or at least about 90% of optimal salinity for the reservoir.

15. The method of claim 1, wherein the alkali-surfactant-polymer slug is optimized for the subsurface reservoir by adjusting one or more of the concentration of alkali, polymer and surfactant to about at least 50%, at least about 60%, at least about 70%, at least about 80%, or at least about 90% of optimal salinity for the reservoir.

16. The method of claim 1, further comprising, prior to injection of the first alkali-polymer slug,

softening seawater or brine water; and

adding alkali and polymer to the softened seawater to form the first alkali-polymer slug.

17. The method of claim 1, further comprising, prior to injection of the first alkali-polymer slug,

softening seawater or brine water; and

adding alkali, polymer, and surfactant to the softened seawater to form alkali-polymer-surfactant slug.

18. The method of claim 1, further comprising, prior to injection of the first alkali-polymer slug,

softening seawater or brine water; and

adding alkali and polymer to the softened seawater to form the second alkali-polymer slug.

19. The method of claim 1, wherein the first alkali-polymer slug, the second alkali-polymer slug, and/or the alkali-polymer-surfactant slug comprises from about 100 to 150,000 ppm total dissolved solids.