COMPOSITIONS AND METHODS FOR TREATING UNCONVENTIONAL SUBTERRANEAN FORMATIONS

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to, and the benefit of U.S. Provisional Application 63/659,802, filed on Jun. 13, 2024, the content of which is hereby incorporated in its entirety.

BACKGROUND

Enhanced oil recovery (EOR) is an increasingly important supplemental technique for recovering oil from a reservoir after primary and secondary recovery. Many hydrocarbon reservoirs trap a significant amount of oil that is bound tightly and difficult to remove by traditional water flooding methods. There is an ongoing need to develop cost-effective and improved additives for oil recovery from hydrocarbon reservoirs.

SUMMARY

Provided herein are methods for treating unconventional subterranean formations. These methods can comprise (a) combining a single-phase liquid surfactant package comprising a primary surfactant with an aqueous-based injection fluid to form a low particle size injection fluid, wherein the primary surfactant comprises an anionic surfactant or a non-ionic surfactant; (b) injecting the low particle size injection fluid into a primary wellbore in fluid communication with the unconventional formation; (c) allowing the low particle size injection fluid to contact the unconventional subterranean formation for a period of time; and (d) producing fluid from the unconventional subterranean formation through one or more secondary wellbores in fluid communication with the primary wellbore. In some embodiments, the method further comprises (e) producing fluid from the unconventional subterranean formation through the primary wellbore after allowing step (c).

In some embodiments, the method can further comprise ceasing injection of the low particle size injection fluid into the primary wellbore before allowing step (c).

In some embodiments, the method comprises producing fluid from the unconventional subterranean formation through one or more secondary wellbores in fluid communication with the primary wellbore during the injecting step (b), during the allowing step (c), after a conclusion of the allowing step (c), or any combination thereof. In certain embodiments, the method comprises producing fluid from the unconventional subterranean formation through one or more secondary wellbores in fluid communication with the primary wellbore during the injecting step (b), during the allowing step (c), and after a conclusion of the allowing step (c).

In some embodiments, the method further comprises monitoring the fluid produced through the one or more secondary wellbores. Monitoring the fluid produced through the one or more secondary wellbores can comprise monitoring the water content of the fluid produced through the one or more secondary wellbores, monitoring for components of the low particle size injection fluid in the fluid produced through the one or more secondary wellbores, monitoring for signs of emulsion and/or foaming in the fluid produced through the one or more secondary wellbores, monitoring for changes in wellhead and/or bottom-hole production pressure in the one or more secondary wellbores, or any combination thereof. In some embodiments, upon observing an increase in the water content of the fluid produced through the one or more secondary wellbore, an increase in a concentration of a component of the low particle size injection fluid in the fluid produced through the one or more secondary wellbores, an increase in emulsion and/or foaming in the fluid produced through the one or more secondary wellbores, an increase in wellhead and/or bottom-hole production pressure in the one or more secondary wellbores, or any combination thereof during the injecting step (b) or during the allowing step (c), the method further comprises temporarily shutting in (ceasing production from) the one or more secondary wellbores.

In some embodiments, injecting step (b) comprises injecting a volume of the low particle size injection fluid equal to from 10% to 250% (e.g., from 25% to 200%) of an estimated stimulated reservoir volume (SRV) of the unconventional formation in fluid communication with the primary wellbore. In certain embodiments, injecting step (b) comprises injecting a volume of the low particle size injection fluid equal to from greater than 100% to 250% (e.g., from greater than 100% to 200%) of the stimulated reservoir volume of the unconventional formation in fluid communication with the primary wellbore.

In some embodiments, injecting step (b) comprises injecting the low particle size injection fluid at a pressure and flow rate that does not substantially initiate new fracture formation within the unconventional subterranean formation. In some embodiments, the low particle size injection fluid is injected at a wellhead pressure of from 0 PSI to 10,000 PSI, such as from 0 PSI to 4,500 PSI, or from 2,000 PSI to 6,000 PSI.

In some embodiments, injecting step (b) and allowing step (c) facilitate release of hydrocarbons from pores in the unconventional subterranean formation.

In some embodiments, allowing step (c) comprises allowing the low particle size injection fluid to contact the unconventional subterranean formation for a period of time of from one day to 60 days, such as from one day to 30 days, from 3 days to 15 days, from 3 days to 12 days, from 5 days to 12 days, from 5 days to 10 days, or from 7 days to 10 days. In some embodiments, allowing step (c) comprises contacting the unconventional subterranean formation with low particle size injection fluid for the period of time.

In some embodiments, the method improves total hydrocarbon recovery from the primary wellbore and the one or more secondary wellbores.

In some embodiments, the injection of the low particle size injection fluid stimulates the unconventional subterranean formation.

The primary surfactant can comprise an anionic surfactant comprising a hydrophobic tail comprising from 6 to 60 carbon atoms or a non-ionic surfactant comprising a hydrophobic tail comprising from 6 to 60 carbon atoms. In some examples, the primary surfactant comprises a non-ionic surfactant, such as a branched or unbranched C6-C32:PO(0-65):EO(0-100), a branched or unbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranched C6-C12:PO(30-40):EO(25-35), a branched or unbranched C6-C30:EO(8-30), or any combination thereof.

In other examples, the primary surfactant comprises an anionic surfactant, such as a sulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate, a carboxylate, a dicarboxylate, a polycarboxylate, or any combination thereof. In some examples, the anionic surfactant can comprise a branched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate, a branched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C12:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C30:EO(8-30)-carboxylate or any combination thereof. In certain examples, the anionic surfactant comprises a surfactant defined by the formula below

wherein R¹ comprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chain comprising at least one oxide group selected from the group consisting of ethylene oxide, propylene oxide, butylene oxide, and combinations thereof; and R³ comprises a branched or unbranched hydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5 carboxylate groups. In certain examples, the anionic surfactant comprises a C10-C30 internal olefin sulfonate, a C8-C30 alkyl benzene sulfonate (ABS), a sulfosuccinate surfactant, or any combination thereof. In certain examples, the anionic surfactant comprises a surfactant defined by the formula below

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and M represents a counterion.

In some embodiments, the aqueous-based injection fluid comprises sea water, brackish water, flowback or produced water, wastewater (e.g., reclaimed or recycled), river water, brine (e.g., reservoir brine, formation brine, or synthetic brine), fresh water (e.g., fresh water comprises <1,000 ppm TDS water), or any combination thereof. In some examples, the aqueous-based injection fluid comprises slickwater. In some examples, the aqueous-based injection fluid comprises at least 10% acid. In some embodiments, the aqueous-based injection fluid comprises a friction reducer, an acid, a gelling agent, a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a corrosion inhibitor, a scale inhibitor, a biocide, a clay stabilizing agent, a proppant, or any combination thereof.

In some embodiments, the primary surfactant has a concentration within the low particle size injection fluid of less than 2.5%, less than 2%, less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, or less than 0.05% by weight, based on the total weight of the low particle size injection fluid. In certain embodiments, the primary surfactant has a concentration within the low particle size injection fluid of from 0.05% to 0.5% by weight, based on the total weight of the low particle size injection fluid.

In some embodiments, the single-phase liquid surfactant package further comprises one or more secondary surfactants. The one or more secondary surfactants can comprise a non-ionic surfactant, an anionic surfactant, a cationic surfactant, a zwitterionic surfactant, or any combination thereof.

In some examples, the non-ionic surfactant can comprise a branched or unbranched C6-C32:PO(0-65):EO(0-100), a branched or unbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranched C6-C12:PO(30-40):EO(25-35), a branched or unbranched C6-C30:EO(8-30), or any combination thereof.

In some examples, the anionic surfactant can comprise a sulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate, a carboxylate, a dicarboxylate, a polycarboxylate, or any combination thereof. In some examples, the anionic surfactant can comprise a branched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate, a branched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C12:PO(30-40):EO(25-35)-carboxylate, a branched or unbranched C6-C30:EO(8-30)-carboxylate or any combination thereof. In certain examples, the anionic surfactant comprises a surfactant defined by the formula below

wherein R¹ comprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chain comprising at least one oxide group selected from the group consisting of ethylene oxide, propylene oxide, butylene oxide, and combinations thereof; and R³ comprises a branched or unbranched hydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5 carboxylate groups. In certain examples, the anionic surfactant comprises a C10-C30 internal olefin sulfonate, a C8-C30 alkyl benzene sulfonate (ABS), a sulfosuccinate surfactant, or any combination thereof. In certain examples, the anionic surfactant comprises a surfactant defined by the formula below

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and M represents a counterion.

When present, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, or less than 0.05%. In certain embodiments, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of from 0.05% to 0.5% by weight, based on the total weight of the low particle size injection fluid.

In some embodiments, the low particle size injection fluid is a single-phase fluid. In some embodiments, combination of the single-phase liquid surfactant package with the aqueous-based injection fluid lowers the particle size distribution of the aqueous-based injection fluid when measured at the temperature and salinity of the subterranean formation. In some embodiments, the mean particle size distribution of the low particle size injection fluid is less than an average pore size of the unconventional subterranean formation.

In some embodiments, the low particle size injection fluid has a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the subterranean formation. In some embodiments, the mean particle size distribution of the low particle size injection fluid is less than 0.05 micrometer in diameter when measured at the temperature and salinity of the subterranean formation. In some embodiments, the aqueous-based injection fluid has a mean particle size distribution of greater than 10 micrometers prior to the addition of the single-phase liquid surfactant package. In some embodiments, the mean particle size distribution of the low particle size injection fluid is at least 10 micrometers smaller than a mean particle size distribution of the aqueous-based injection fluid.

In some embodiments, the low particle size injection fluid further comprises an acid, a friction reducer, a gelling agent, a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a corrosion inhibitor, a scale inhibitor, a biocide, a clay stabilizing agent, a proppant, or any combination thereof. In certain embodiments, the low particle size injection fluid further comprises a wettability alteration chemical. In certain embodiments, the single-phase liquid surfactant package further comprises one or more co-solvents, such as a C1-C5 alcohol, an ethoxylated C1-C5 alcohol, or any combination thereof. In some embodiments, the low particle size injection fluid is substantially free of proppant.

In some embodiments, the low particle size injection fluid has a total surfactant concentration of from 0.01% to 1% by weight, based on the total weight of the low particle size injection fluid.

In some embodiments, the unconventional subterranean formation has a temperature of from 75° F. to 350° F., such as from 150° F. to 250° F. In some embodiments, the unconventional subterranean formation has a salinity of at least 5,000 ppm TDS, such as at least 100,000 ppm TDS. In certain embodiments, the subterranean formation has a salinity of from 100,000 ppm to 300,000 ppm TDS. In some embodiments, the unconventional subterranean formation has a permeability of less than 25 mD, such as from 10 to 0.1 millidarcy (mD).

In some embodiments, the method further comprises identifying one or more secondary wellbores that are in fluid communication with the primary wellbore. The one or more secondary wellbores that are in fluid communication with the primary wellbore can be identified and selected for use in the methods described herein by, for example, performing a tracer study to identify one or more secondary wellbores in fluid communication with the primary wellbore. In some embodiments, the one or more secondary wellbores that are in fluid communication with the primary wellbore can be identified and/or selected by a method that comprises (i) injecting a tracer into a primary wellbore in fluid communication with the unconventional formation; (ii) measuring a tracer response in a plurality of wellbores in geographic proximity to the primary wellbore; and (iii) using the tracer response to identify the one or more secondary wellbores in fluid communication with the primary wellbore. The tracer response can comprise tracer mass recovery, rate of tracer recovery, and/or tracer concentration profile in the plurality of wellbores in geographic proximity to the primary wellbore. In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises analysis of fracture driven interactions between wellbores present in fluid communication with the unconventional subterranean formation. In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises a pressure transient analysis (e.g., by observing which wellbores exhibit a change in wellhead and/or bottom-hole pressure in response to changes in pressure at the primary wellbore). In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises analysis of geological features of the unconventional subterranean formation, such as naturally occurring faults or fractures.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a workflow to develop stimulation fluid for boosting mid-life oil production of unconventional wells.

FIG. 2 depicts a two-dimensional schematic of natural fracture intersected by hydraulic fractures in an unconventional well (left). On the right, an equivalent fracture swarm model developed using the Fractional Dimension Rate Transient Analysis (RTA) is shown.

FIG. 3 depicts a workflow for EDFM fracture swarm model creation for history matching and prediction.

FIGS. 4A-4B depicts a history match on oil (FIG. 4A) and water (FIG. 4B) production rates obtained using the RTA trained fracture swarm model.

FIG. 5 depicts a schematic of a field injection set up.

FIG. 6 depicts a surveillance, analysis and optimization matrix.

FIG. 7 is a plot showing the field data and the corresponding history match of the pre- and post-stimulation section.

FIG. 8 depicts reference well production rates and a pre-injection oil decline curve.

FIG. 9 depicts reference well oil cumulative production and pre-injection cumulative oil decline.

FIG. 10 depicts well production rates and a pre-injection oil decline curve.

FIG. 11 depicts surfactant well oil cumulative production and pre-injection cumulative oil decline.

FIG. 12 depicts reference and surfactant wells productivity index before and after injection.

FIGS. 13A-13B depict decline curve analysis for EUR estimation. FIG. 13A shows the reference well. FIG. 13B shows the surfactant well.

FIGS. 14A-14B depict RTA before (FIG. 14A) and after (FIG. 14B) injection for the reference well.

FIGS. 15A-15B depict RTA before (FIG. 15A) and after (FIG. 15B) injection for the surfactant well.

FIGS. 16A-16C depict tracer response for water injection in unconventional wells. FIG. 16A shows a bubble map of tracer mass recovery where the surface area of bubbles is proportional to tracer recovery. Horizontal wells are denoted by “H” and vertical wells by “V”. Tracer confirms a greater-than-expected interwell connectivity. FIG. 16B shows tracer response versus time for the reference well and its two primary offsets. FIG. 16C shows cumulative tracer mass recovery for Reference water well with ˜37% mass recovery compared to ˜14% for Surfactant well. The significantly lower tracer recovery in Surfactant wells is accompanied by higher oil recovery, indicating a successful enhanced imbibition by surfactant.

FIGS. 17A-17B depict produced surfactant for an offset vertical well (FIG. 17A) and the surfactant well (FIG. 17B). Surfactant breakthrough in offset vertical well along with tracer confirms integrity of the slug during flow in fracture network & well lateral while lower surfactant flowback (from treated well) along with increased oil production confirms surfactant adsorption.

FIGS. 18A-18B depict salinity and tracer response in (FIG. 18A) the Reference well and (FIG. 18B) its primary offset. Salinity remains well-above the injected salinity, confirming mixing with formation brine. In the case of offset well, the mixing occurs during flow through fracture system as well as merging with water produced from untreated sections of the offset well. In the case of the Reference well, which is shut-in before flowback, brine mixing indicates a lack of equilibrium in the horizontal well and “water sloshing” in fracture system.

FIG. 19 depicts pilot execution workflow.

FIGS. 20A-20B show thermographic images of 3-phase separator vessels: FIG. 20A vessel with mild solids build up (bottom right), FIG. 20B vessel with severe solids build up (vessel bottom) after several new wells put online for production flowing into the facility prior to scheduled maintenance. FIG. 20B would require additional precautions taken during execution planning for field management during injection and flowback.

FIG. 21 shows an image of aqueous stability test samples with CS-1 formulation at reservoir temperature (165° F.).

FIG. 22 shows an image of phase behavior test samples with clean interphase using CS-1 formulation at reservoir temperature (165° F.).

FIGS. 23A-23B depict contact angle measurement versus time for selected rock and surfactant CS-1. (FIG. 23A) graphical scheme, (FIG. 23B) plot.

FIG. 24 depicts IFT measurement versus time for selected brine and surfactant solution CS-1.

FIGS. 25A-25B are a plots of Oil recovery by brine and surfactant solution injection. Results show that using surfactant injection can stimulate oil recovery in both tertiary (FIG. 25A) and secondary (FIG. 25B) methods for shale and tight rock reservoirs.

FIGS. 26A-26E are scatter plot responses for the pilot well set: FIG. 26A time online at treatment (years) vs net oil uplift (BO), FIG. 26B soak or shut-in time post treatment (days) vs net oil uplift (BO), FIG. 26C Average surfactant concentration (ppm) vs net oil uplift (BO), FIG. 26D treatment intensity, BW/lateral ft (1:High, 0:Low) vs net oil uplift (BO), FIG. 26E offset communication (1: yes, 0: no) vs distance to nearest neighbor (ft).

FIG. 27 shows well 1 baseline and post-treatment oil DCA response.

FIGS. 28A-28B show well 1 pre- and post-treatment responses: pressure normalized oil rate vs. oil material balance time (FIG. 28A) and mass rate normalized density change vs. mass material balance time (FIG. 28B).

FIG. 29 shows well 5 baseline and post-treatment oil DCA response.

FIGS. 30A-30B show well 5 pre- and post-treatment responses: pressure normalized oil rate vs. oil material balance time (FIG. 30A) and mass rate normalized density change vs. mass material balance time (FIG. 30B).

FIG. 31 shows well 7 baseline and post-treatment oil DCA response.

FIGS. 32A-32B show well 7 pre- and post-treatment responses: pressure normalized oil rate vs. oil material balance time (FIG. 32A) and mass rate normalized density change vs. mass material balance time (FIG. 32B).

The drawings illustrate only example embodiments of methods, systems, and devices for stabilizing injection fluids and are therefore not to be considered limiting of its scope, as aspects of the disclosure may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positionings may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

DETAILED DESCRIPTION

A number of embodiments of the disclosure have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

Definitions

To facilitate understanding of the disclosure set forth herein, a number of terms are defined below. Unless defined otherwise, all technical and scientific terms used herein generally have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. Unless otherwise specified, all percentages are in weight percent and the pressure is in atmospheres. All citations referred to herein are expressly incorporated by reference.

General Definitions

As used in this specification and the following claims, the terms “comprise” (as well as forms, derivatives, or variations thereof, such as “comprising” and “comprises”) and “include” (as well as forms, derivatives, or variations thereof, such as “including” and “includes”) are inclusive (i.e., open-ended) and do not exclude additional elements or steps. For example, the terms “comprise” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Other than where noted, all numbers expressing quantities of ingredients, reaction conditions, geometries, dimensions, and so forth used in the specification and claims are to be understood at the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, to be construed in light of the number of significant digits and ordinary rounding approaches.

Accordingly, these terms are intended to not only cover the recited element(s) or step(s), but may also include other elements or steps not expressly recited. Furthermore, as used herein, the use of the terms “a”, “an”, and “the” when used in conjunction with an element may mean “one,” but it is also consistent with the meaning of “one or more,” “at least one,” and “one or more than one.” Therefore, an element preceded by “a” or “an” does not, without more constraints, preclude the existence of additional identical elements.

Ranges can be expressed herein as from “about” one particular value, and/or to “about” another particular value. By “about” is meant within 10% of the value, e.g., within 9, 8, 7, 6, 5, 4, 3, 2, or 1% of the value. When such a range is expressed, another aspect includes from the one particular value and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another aspect. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint. It is also understood that there are a number of values disclosed herein, and that each value is also herein disclosed as “about” that particular value in addition to the value itself. For example, if the value “10” is disclosed, then “about 10” is also disclosed. A range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) can includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

As used herein, the terms “may,” “optionally,” and “may optionally” are used interchangeably and are meant to include cases in which the condition occurs as well as cases in which the condition does not occur. Thus, for example, the statement that a formulation “may include an excipient” is meant to include cases in which the formulation includes an excipient as well as cases in which the formulation does not include an excipient.

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if a composition is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the composition described by this phrase could include only a component of type A. In some embodiments, the composition described by this phrase could include only a component of type B. In some embodiments, the composition described by this phrase could include only a component of type C. In some embodiments, the composition described by this phrase could include a component of type A and a component of type B. In some embodiments, the composition described by this phrase could include a component of type A and a component of type C. In some embodiments, the composition described by this phrase could include a component of type B and a component of type C. In some embodiments, the composition described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the composition described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the composition described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the composition described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the composition described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the composition described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the composition described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

The term “hydrocarbon” refers to a compound containing only carbon and hydrogen atoms.

“Hydrocarbon-bearing formation” or simply “formation” refers to the rock matrix in which a wellbore may be drilled. For example, a formation refers to a body of rock that is sufficiently distinctive and continuous such that it can be mapped. It should be appreciated that while the term “formation” generally refers to geologic formations of interest, that the term “formation,” as used herein, may, in some instances, include any geologic points or volumes of interest (such as a survey area).

“Unconventional formation” is a subterranean hydrocarbon-bearing formation that generally requires intervention in order to recover hydrocarbons from the reservoir at economic flow rates or volumes. For example, an unconventional formation includes reservoirs having an unconventional microstructure in which fractures are used to recover hydrocarbons from the reservoir at sufficient flow rates or volumes (e.g., an unconventional reservoir generally needs to be fractured under pressure or have naturally occurring fractures in order to recover hydrocarbons from the reservoir at sufficient flow rates or volumes).

In some embodiments, the unconventional formation can include a reservoir having a permeability of less than 25 millidarcy (mD) (e.g., 20 mD or less, 15 mD or less, 10 mD or less, 5 mD or less, 1 mD or less, 0.5 mD or less, 0.1 mD or less, 0.05 mD or less, 0.01 mD or less, 0.005 mD or less, 0.001 mD or less, 0.0005 mD or less, 0.0001 mD or less, 0.00005 mD or less, 0.00001 mD or less, 0.000005 mD or less, 0.000001 mD or less, or less). In some embodiments, the unconventional formation can include a reservoir having a permeability of at least 0.000001 mD (e.g., at least 0.000005 mD, at least 0.00001 mD, 0.00005 mD, at least 0.0001 mD, 0.0005 mD, 0.001 mD, at least 0.005 mD, at least 0.01 mD, at least 0.05 mD, at least 0.1 mD, at least 0.5 mD, at least 1 mD, at least 5 mD, at least 10 mD, at least 15 mD, or at least 20 mD).

The unconventional formation can include a reservoir having a permeability ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the unconventional formation can include a reservoir having a permeability of from 0.000001 mD to 25 mD (e.g., from 0.001 mD to 25 mD, from 0.001 mD to 10 mD, from 0.01 mD to 10 mD, from 0.1 mD to 10 mD, from 0.001 mD to 5 mD, from 0.01 mD to 5 mD, or from 0.1 mD to 5 mD). When referring to a permeability value of a formation, the permeability value can comprise an average value for the permeability of samples across a region of the formation.

The formation may include faults, fractures (e.g., naturally occurring fractures, fractures created through hydraulic fracturing, etc.), geobodies, overburdens, underburdens, horizons, salts, salt welds, etc. The formation may be onshore, offshore (e.g., shallow water, deep water, etc.), etc. Furthermore, the formation may include hydrocarbons, such as liquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons, a combination of liquid hydrocarbons and gas hydrocarbons (e.g., including gas condensate), etc.

The formation, the hydrocarbons, or both may also include non-hydrocarbon items, such as pore space, connate water, brine, fluids from enhanced oil recovery, etc. The formation may also be divided up into one or more hydrocarbon zones, and hydrocarbons can be produced from each desired hydrocarbon zone.

The term formation may be used synonymously with the term “reservoir” or “subsurface reservoir” or “subsurface region of interest” or “subsurface formation” or “subsurface volume of interest” or “subterranean formation”. For example, in some embodiments, the reservoir may be, but is not limited to, a shale reservoir, a carbonate reservoir, a tight sandstone reservoir, a tight siltstone reservoir, etc. Indeed, the terms “formation,” “hydrocarbon,” and the like are not limited to any description or configuration described herein.

A “wellbore” refers to a single hole, usually cylindrical, that is drilled into a subsurface volume of interest. A wellbore may be drilled in one or more directions. For example, a wellbore may include a vertical wellbore, a horizontal wellbore, a deviated wellbore, and/or other type of wellbore. A wellbore may be drilled in the formation for exploration and/or recovery of resources. For example, a wellbore may be drilled in the formation to aid in extraction and/or production of resources such as hydrocarbons. As another example, a wellbore may be drilled in the formation for fluid injection. A plurality of wellbores (e.g., tens to hundreds of wellbores) are often used in a field depending on the desired outcome.

A wellbore may be drilled into a formation using practically any drilling technique and equipment known in the art, such as geosteering, directional drilling, etc. Drilling the wellbore may include using a tool, such as a drilling tool that includes a drill bit and a drill string. Drilling fluid, such as drilling mud, may be used while drilling in order to cool the drill tool and remove cuttings. Other tools may also be used while drilling or after drilling, such as measurement-while-drilling (MWD) tools, seismic-while-drilling (SWD) tools, wireline tools, logging-while-drilling (LWD) tools, or other downhole tools. After drilling to a predetermined depth, the drill string and the drill bit may be removed, and then the casing, the tubing, and/or other equipment may be installed according to the design of the wellbore may be installed according to the design of the wellbore. The equipment to be used in drilling the wellbore may be dependent on the design of the wellbore, the formation, the hydrocarbons, and/or other factors.

A wellbore may include a plurality of components, such as, but not limited to, a casing, a liner, a tubing string, a sensor, a packer, a screen, a gravel pack, artificial lift equipment (e.g., an electric submersible pump (ESP)), and/or other components. If a wellbore is drilled offshore, the wellbore may include one or more of the previous components plus other offshore components, such as a riser. A wellbore may also include equipment to control fluid flow into the wellbore, control fluid flow out of the wellbore, or any combination thereof. For example, a wellbore may include a wellhead, a choke, a valve, and/or other control devices. These control devices may be located on the surface, in the subsurface (e.g., downhole in the wellbore), or any combination thereof. In some embodiments, the same control devices may be used to control fluid flow into and out of the wellbore. In some embodiments, different control devices may be used to control fluid flow into and out of a wellbore. In some embodiments, the rate of flow of fluids through the wellbore may depend on the fluid handling capacities of the surface facility that is in fluidic communication with the wellbore. The equipment to be used in controlling fluid flow into and out of a wellbore may be dependent on the wellbore, the formation, the surface facility, and/or other factors. Moreover, sand control equipment and/or sand monitoring equipment may also be installed (e.g., downhole and/or on the surface). A wellbore may also include any completion hardware that is not discussed separately. The term “wellbore” may be used synonymously with the terms “borehole,” “well,” or “well bore.” The term “wellbore” is not limited to any description or configuration described herein.

“Single-phase liquid or fluid,” as used herein, refers to a fluid which only has a single-phase, i.e. only a water phase. A single-phase fluid is not an emulsion. A single-phase fluid is in a thermodynamically stable state such that it does not macroscopically separate into distinct layers or precipitate out solid particles. In some embodiments, the single-phase liquid comprises a single-phase liquid surfactant package including one or more anionic and/or non-ionic surfactants.

“Aqueous stable,” as used herein, refers to a solution whose soluble components remain dissolved and is a single phase as opposed to precipitating as particulates or phase separating into 2 or more phases. As such, aqueous stable solutions are clear and transparent statically and when agitated. Conversely, solutions may be described as “aqueous unstable” when components precipitate from solution as particulates or phase separates into 2 or more phases. The aqueous stability of solutions can be assessed by evaluating whether the Tyndall Effect (light scattering by suspended particulates) is observed when monochromatic light is directed through the solution. If a sample exhibits the Tyndall effect, the solution may be characterized as “aqueous unstable.” Conversely, if a sample does not exhibit the Tyndall effect, the solution may be characterized as “aqueous stable.”

“Slickwater,” as used herein, refers to water-based injection fluid comprising a friction reducer which is typically pumped at high rates to fracture a reservoir. Optionally when employing slickwater, smaller sized proppant particles (e.g., 40/70 or 50/140 mesh size) are used due to the fluid having a relatively low viscosity (and therefore a diminished ability to transport sizable proppants relative to more viscous fluids). In some embodiments, proppants are added to some stages of completion/stimulation during production of an unconventional reservoir. In some embodiments, slickwater is injected with a small quantity of proppant.

“Friction reducer,” as used herein, refers to a chemical additive that alters fluid rheological properties to reduce friction created within the fluid as it flows through small-diameter tubulars or similar restrictions (e.g., valves, pumps). Generally polymers, or similar friction reducing agents, add viscosity to the fluid, which reduces the turbulence induced as the fluid flows. Reductions in fluid friction of greater than 50% are possible depending on the friction reducer utilized, which allows the injection fluid to be injected into a wellbore at a much higher injection rate (e.g., between 60 to 100 barrels per minute) and also lower pumping pressure during proppant injection.

“Injection fluid” or “LPS injection fluid,” as used herein, refers to any fluid which is injected into a reservoir via a well. The injection fluid may include one or more of an acid, a polymer, a friction reducer, a gelling agent, a crosslinker, a scale inhibitor, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a corrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, a wettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, or an alkoxylated C1-C5 alcohol), or any combination thereof, to increase the efficacy of the injection fluid.

“Low particle size injection fluid” refers to an injection fluid having a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the unconventional formation for which injection is to occur. For example, the low particle size injection fluid can be formed by mixing an aqueous-based injection fluid with a single-phase fluid comprising a single-phase liquid surfactant package. Prior to being dosed with the anionic or non-ionic surfactant to form the low particle size injection fluid, the aqueous based fluid may have been used as the injection fluid.

The term “interfacial tension” or “IFT” as used herein refers to the surface tension between test oil and water of different salinities containing a surfactant formulation at different concentrations. Typically, interfacial tensions are measured using a spinning drop tensiometer or calculated from phase behavior experiments.

The term “proximate” is defined as “near”. If item A is proximate to item B, then item A is near item B. For example, in some embodiments, item A may be in contact with item B. For example, in some embodiments, there may be at least one barrier between item A and item B such that item A and item B are near each other, but not in contact with each other. The barrier may be a fluid barrier, a non-fluid barrier (e.g., a structural barrier), or any combination thereof. Both scenarios are contemplated within the meaning of the term “proximate.”

Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. Unless otherwise specified, all percentages are in weight percent and the pressure is in atmospheres.

Compositions

Described herein are single-phase liquid surfactant packages which decrease the particle size distribution when combined with an aqueous-based injection fluid to create a low particle size (LPS) injection fluid. The low particle size injection fluid can have a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of an unconventional subterranean formation into which they are injected. In specific embodiments, after injection into a reservoir, the LPS injection fluid retains the lowered particle size distribution within the reservoir. In certain embodiments, the LPS injection fluid lowers the particle size distribution of the reservoir fluid after being injected into the reservoir and mixing with the reservoir fluid. In embodiments, the aqueous-based injection fluid when combined with the single-phase liquid surfactant package maintains itself as a single-phase, that is, as the LPS injection fluid is pumped downhole it remains a homogenous single-phase solution within the reservoir, even when mixed with the native reservoir fluid.

The single-phase liquid surfactant package can include a primary surfactant and optionally one or more secondary surfactants. The primary surfactant can include an anionic surfactant or a non-ionic surfactant. The anionic surfactant or the non-ionic surfactant can comprise a hydrophobic tail comprising from 6 to 60 carbon atoms. In some embodiments, the primary surfactant can include a non-ionic surfactant. In some embodiments, the primary surfactant can include an anionic surfactant. In some embodiments, the surfactant package can further comprise one or more secondary surfactants. In some embodiments, the one or more secondary surfactants can comprise one or more non-ionic surfactants, one or more anionic surfactants, one or more cationic surfactants, one or more zwitterionic surfactants, or any combination thereof.

In some embodiments, the primary surfactant can comprise at least 10% by weight (e.g., at least 15% by weight, at least 20% by weight, at least 25% by weight, at least 30% by weight, at least 35% by weight, at least 40% by weight, at least 45% by weight, at least 50% by weight, at least 55% by weight, at least 60% by weight, at least 65% by weight, at least 70% by weight, at least 75% by weight, at least 80% by weight, or at least 85% by weight) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package. In some embodiments, the primary surfactant can comprise 90% by weight or less (e.g., 85% by weight or less, 80% by weight or less, 75% by weight or less, 70% by weight or less, 65% by weight or less, 60% by weight or less, 55% by weight or less, 50% by weight or less, 45% by weight or less, 40% by weight or less, 35% by weight or less, 30% by weight or less, 25% by weight or less, 20% by weight or less, or 15% by weight or less) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package.

The primary surfactant can be present in the single-phase liquid surfactant package in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the primary surfactant can comprise from 10% to 90% by weight (e.g., from 10% to 50% by weight) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package.

In some embodiments, the one or more secondary surfactants can comprise at least 10% by weight (e.g., at least 15% by weight, at least 20% by weight, at least 25% by weight, at least 30% by weight, at least 35% by weight, at least 40% by weight, at least 45% by weight, at least 50% by weight, at least 55% by weight, at least 60% by weight, at least 65% by weight, at least 70% by weight, at least 75% by weight, at least 80% by weight, or at least 85% by weight) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package. In some embodiments, the one or more secondary surfactants can comprise 90% by weight or less (e.g., 85% by weight or less, 80% by weight or less, 75% by weight or less, 70% by weight or less, 65% by weight or less, 60% by weight or less, 55% by weight or less, 50% by weight or less, 45% by weight or less, 40% by weight or less, 35% by weight or less, 30% by weight or less, 25% by weight or less, 20% by weight or less, or 15% by weight or less) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package.

The one or more secondary surfactants can be present in the single-phase liquid surfactant package in an amount ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the one or more secondary surfactants can comprise from 10% to 90% by weight (e.g., from 10% to 50% by weight) of the single-phase liquid surfactant package, based on the total weight of the single-phase liquid surfactant package.

In some embodiments, the single-phase liquid surfactant package can comprise a non-ionic surfactant. In other embodiments, the single-phase liquid surfactant package can consist essentially of a non-ionic surfactant (i.e., the non-ionic surfactant(s) is the only surfactant present in the single-phase liquid surfactant package). In other embodiments, the single-phase liquid surfactant package can consist of a non-ionic surfactant. In some of these embodiments, the single-phase liquid surfactant package further includes water. In some of these embodiments, the single-phase liquid surfactant package does not comprise a hydrocarbon.

In some embodiments, the single-phase liquid surfactant package can comprise an anionic surfactant. In other embodiments, the single-phase liquid surfactant package can consist essentially of an anionic surfactant (i.e., the anionic surfactant(s) is the only surfactant present in the single-phase liquid surfactant package). In other embodiments, the single-phase liquid surfactant package can consist of an anionic surfactant. In some of these embodiments, the single-phase liquid surfactant package further includes water. In some of these embodiments, the single-phase liquid surfactant package does not comprise a hydrocarbon.

In some embodiments, the single-phase liquid surfactant package can comprise an anionic surfactant and a non-ionic surfactant. In other embodiments, the single-phase liquid surfactant package can consist essentially of an anionic surfactant and a non-ionic surfactant (i.e., the anionic surfactant and the non-ionic surfactant are the only surfactants present in the single-phase liquid surfactant package). In other embodiments, the single-phase liquid surfactant package can consist of an anionic surfactant and a non-ionic surfactant. In some of these embodiments, the single-phase liquid surfactant package further includes water. In some of these embodiments, the single-phase liquid surfactant package does not comprise a hydrocarbon.

In some embodiments, the single-phase liquid surfactant package can comprise a non-ionic surfactant, an anionic surfactant, and a second anionic surfactant. In other embodiments, the single-phase liquid surfactant package can consist essentially of a non-ionic surfactant, an anionic surfactant, and a second anionic surfactant (i.e., the anionic surfactant, the second anionic surfactant, and the non-ionic surfactant are the only surfactants present in the single-phase liquid surfactant package). In other embodiments, the single-phase liquid surfactant package can consist of a non-ionic surfactant, an anionic surfactant, and a second anionic surfactant. In some of these embodiments, the single-phase liquid surfactant package further includes water. In some of these embodiments, the single-phase liquid surfactant package does not comprise a hydrocarbon.

Suitable anionic surfactants for use as a primary surfactant and/or a secondary surfactant include compounds that can be added to increase wettability. In embodiments, the hydrophilic-lipophilic balance (HLB) of the non-ionic surfactant is greater than 10 (e.g., greater than 9, greater than 8, or greater than 7). In some embodiments, the HLB of the non-ionic surfactant is from 7 to 10.

The non-ionic surfactant can comprise a hydrophobic tail comprising from 6 to 60 carbon atoms. In some embodiments, the non-ionic surfactant can include a hydrophobic tail that comprises at least 6 carbon atoms (e.g., at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbon atoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12 carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, at least 15 carbon atoms, at least 16 carbon atoms, at least 17 carbon atoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20 carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, at least 23 carbon atoms, at least 24 carbon atoms, at least 25 carbon atoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28 carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, at least 31 carbon atoms, at least 32 carbon atoms, at least 33 carbon atoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36 carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, at least 39 carbon atoms, at least 40 carbon atoms, at least 41 carbon atoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44 carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, at least 47 carbon atoms, at least 48 carbon atoms, at least 49 carbon atoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52 carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, at least 55 carbon atoms, at least 56 carbon atoms, at least 57 carbon atoms, at least 58 carbon atoms, or at least 59 carbon atoms). In some embodiments, the non-ionic surfactant can include a hydrophobic tail that comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less, 58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms or less, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atoms or less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbon atoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47 carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less, 44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms or less, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atoms or less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbon atoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33 carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less, 30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms or less, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atoms or less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbon atoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19 carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less, 16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms or less, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atoms or less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atoms or less, or 7 carbon atoms or less).

The non-ionic surfactant can include a hydrophobic tail that comprises a number of carbon atoms ranging from any of the minimum values described above to any of the maximum values described above. For example, the non-ionic surfactant can comprise a hydrophobic tail comprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60, from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32, from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to 42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16 to 25, from 26 to 35, or from 36 to 45 carbon atoms. In some cases, the hydrophobic tail may be a straight chain, branched chain, and/or may comprise cyclic structures. The hydrophobic carbon tail may comprise single bonds, double bonds, triple bonds, or any combination thereof. In some cases, the hydrophobic tail can comprise an alkyl group, with or without an aromatic ring (e.g., a phenyl ring) attached to it. In some embodiments, the hydrophobic tail can comprise a branched hydrophobic tail derived from Guerbet alcohols.

Example non-ionic surfactants include alkyl aryl alkoxy alcohols, alkyl alkoxy alcohols, or any combination thereof. In embodiments, the non-ionic surfactant may be a mix of surfactants with different length lipophilic tail chain lengths. For example, the non-ionic surfactant may be C9-C11:9EO, which indicates a mixture of non-ionic surfactants that have a lipophilic tail length of 9 carbon to 11 carbon, which is followed by a chain of 9 EOs. The hydrophilic moiety is an alkyleneoxy chain (e.g., an ethoxy (EO), butoxy (BO) and/or propoxy (PO) chain with two or more repeating units of EO, BO, and/or PO). In some embodiments, 1-100 repeating units of EO are present. In some embodiments, 0-65 repeating units of PO are present. In some embodiments, 0-25 repeating units of BO are present. For example, the non-ionic surfactant could comprise 10EO:5PO or 5EO. In embodiments, the non-ionic surfactant may be a mix of surfactants with different length lipophilic tail chain lengths. For example, the non-ionic surfactant may be C9-C11:PO9:EO2, which indicates a mixture of non-ionic surfactants that have a lipophilic tail length of 9 carbon to 11 carbon, which is followed by a chain of 9 POs and 2 EOs. In specific embodiments, the non-ionic surfactant is linear C9-C11:9EO. In some embodiments, the non-ionic surfactant is a Guerbet PO(0-65) and EO(0-100) (Guerbet can be C6-C36); or alkyl PO(0-65) and EO(0-100): where the alkyl group is linear or branched C1-C36. In some examples, the non-ionic surfactant can comprise a branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., a branched or unbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranched C6-C12:PO(30-40):EO(25-35), a branched or unbranched C6-30:EO(8-30), or any combination thereof). In some embodiments, the non-ionic surfactant is one or more alkyl polyglucosides.

Suitable anionic surfactants for use as a secondary surfactant include a hydrophobic tail that comprises from 6 to 60 carbon atoms. In some embodiments, the anionic surfactant can include a hydrophobic tail that comprises at least 6 carbon atoms (e.g., at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbon atoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12 carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, at least 15 carbon atoms, at least 16 carbon atoms, at least 17 carbon atoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20 carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, at least 23 carbon atoms, at least 24 carbon atoms, at least 25 carbon atoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28 carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, at least 31 carbon atoms, at least 32 carbon atoms, at least 33 carbon atoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36 carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, at least 39 carbon atoms, at least 40 carbon atoms, at least 41 carbon atoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44 carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, at least 47 carbon atoms, at least 48 carbon atoms, at least 49 carbon atoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52 carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, at least 55 carbon atoms, at least 56 carbon atoms, at least 57 carbon atoms, at least 58 carbon atoms, or at least 59 carbon atoms). In some embodiments, the anionic surfactant can include a hydrophobic tail that comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less, 58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms or less, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atoms or less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbon atoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47 carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less, 44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms or less, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atoms or less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbon atoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33 carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less, 30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms or less, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atoms or less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbon atoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19 carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less, 16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms or less, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atoms or less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atoms or less, or 7 carbon atoms or less).

The anionic surfactant can include a hydrophobic tail that comprises a number of carbon atoms ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the anionic surfactant can comprise a hydrophobic tail comprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60, from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32, from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to 42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16 to 25, from 26 to 35, or from 36 to 45 carbon atoms. The hydrophobic (lipophilic) carbon tail may be a straight chain, branched chain, and/or may comprise cyclic structures. The hydrophobic carbon tail may comprise single bonds, double bonds, triple bonds, or any combination thereof. In some embodiments, the anionic surfactant can include a branched hydrophobic tail derived from Guerbet alcohols. The hydrophilic portion of the anionic surfactant can comprise, for example, one or more sulfate moieties (e.g., one, two, or three sulfate moieties), one or more sulfonate moieties (e.g., one, two, or three sulfonate moieties), one or more sulfosuccinate moieties (e.g., one, two, or three sulfosuccinate moieties), one or more carboxylate moieties (e.g., one, two, or three carboxylate moieties), or any combination thereof.

In some embodiments, the anionic surfactant can comprise, for example a sulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate, a carboxylate, a dicarboxylate, a polycarboxylate, or any combination thereof. In some examples, the anionic surfactant can comprise an internal olefin sulfonate (IOS), an isomerized olefin sulfonate, an alfa olefin sulfonate (AOS), an alkyl aryl sulfonate (AAS), a xylene sulfonate, an alkane sulfonate, a petroleum sulfonate, an alkyl diphenyl oxide (di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxy sulfonate, an alkoxy carboxylate, an alcohol phosphate, or an alkoxy phosphate. In some embodiments, the anionic surfactant can comprise an alkoxy carboxylate surfactant, an alkoxy sulfate surfactant, an alkoxy sulfonate surfactant, an alkyl sulfonate surfactant, an aryl sulfonate surfactant, or an olefin sulfonate surfactant.

An “alkoxy carboxylate surfactant” or “alkoxy carboxylate” refers to a compound having an alkyl or aryl attached to one or more alkoxylene groups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which, in turn is attached to —COO⁻ or acid or salt thereof including metal cations such as sodium. In embodiments, the alkoxy carboxylate surfactant can be defined by the formulae below:

• • wherein R¹ is substituted or unsubstituted C6-C36 alkyl or substituted or unsubstituted aryl; R² is, independently for each occurrence within the compound, hydrogen or unsubstituted C1-C6 alkyl; R³ is independently hydrogen or unsubstituted C1-C6 alkyl, n is an integer from 0 to 175, z is an integer from 1 to 6 and M⁺ is a monovalent, divalent or trivalent cation. In some of these embodiments, R¹ can be an unsubstituted linear or branched C6-C36 alkyl.

In certain embodiments, the alkoxy carboxylate can be a C6-C32:PO(0-65):EO(0-100)-carboxylate (i.e., a C6-C32 hydrophobic tail, such as a branched or unbranched C6-C32 alkyl group, attached to from 0 to 65 propyleneoxy groups (—CH₂—CH(methyl)-O-linkers), attached in turn to from 0 to 100 ethyleneoxy groups (—CH₂—CH₂—O— linkers), attached in turn to —COO⁻ or an acid or salt thereof including metal cations such as sodium). In certain embodiments, the alkoxy carboxylate can be a branched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate. In certain embodiments, the alkoxy carboxylate can be a branched or unbranched C6-C12:PO(30-40):EO(25-35)-carboxylate. In certain embodiments, the alkoxy carboxylate can be a branched or unbranched C6-C30:EO(8-30)-carboxylate.

An “alkoxy sulfate surfactant” or “alkoxy sulfate” refers to a surfactant having an alkyl or aryl attached to one or more alkoxylene groups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which, in turn is attached to —SO₃⁻ or acid or salt thereof including metal cations such as sodium. In some embodiment, the alkoxy sulfate surfactant has the formula R—(BO)_e—(PO)_f-(EO)_g—SO₃⁻or acid or salt (including metal cations such as sodium) thereof, wherein R is C6-C32 alkyl, BO is —CH₂—CH(ethyl)-O—, PO is —CH₂—CH(methyl)-O—, and EO is —CH₂—CH₂—O—. The symbols e, f and g are integers from 0 to 50 wherein at least one is not zero.

In embodiments, the alkoxy sulfate surfactant can be an aryl alkoxy sulfate surfactant. The aryl alkoxy surfactant can be an alkoxy surfactant having an aryl attached to one or more alkoxylene groups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which, in turn is attached to—SO₃⁻ or acid or salt thereof including metal cations such as sodium.

An “alkyl sulfonate surfactant” or “alkyl sulfonate” refers to a compound that includes an alkyl group (e.g., a branched or unbranched C6-C32 alkyl group) attached to—SO₃⁻ or acid or salt thereof including metal cations such as sodium.

An “aryl sulfate surfactant” or “aryl sulfate” refers to a compound having an aryl group attached to —O-SO₃⁻ or acid or salt thereof including metal cations such as sodium. An “aryl sulfonate surfactant” or “aryl sulfonate” refers to a compound having an aryl group attached to—SO₃⁻ or acid or salt thereof including metal cations such as sodium. In some cases, the aryl group can be substituted, for example, with an alkyl group (an alkyl aryl sulfonate).

An “internal olefin sulfonate,” “isomerized olefin sulfonate,” or “IOS” refers to an unsaturated hydrocarbon compound comprising at least one carbon-carbon double bond and at least one SO₃⁻ group, or a salt thereof. As used herein, a “C20-C28 internal olefin sulfonate,” “a C20-C28 isomerized olefin sulfonate,” or “C20-C28 IOS” refers to an IOS, or a mixture of IOSs with an average carbon number of 20 to 28, or of 23 to 25. The C20-C28 IOS may comprise at least 80% of IOS with carbon numbers of 20 to 28, at least 90% of IOS with carbon numbers of 20 to 28, or at least 99% of IOS with carbon numbers of 20 to 28. As used herein, a “C15-C18 internal olefin sulfonate,” “C15-C18 isomerized olefin sulfonate,” or “C15-C18 IOS” refers to an IOS or a mixture of IOSs with an average carbon number of 15 to 18, or of 16 to 17. The C15-C18 IOS may comprise at least 80% of IOS with carbon numbers of 15 to 18, at least 90% of IOS with carbon numbers of 15 to 18, or at least 99% of IOS with carbon numbers of 15 to 18. The internal olefin sulfonates or isomerized olefin sulfonates may be alpha olefin sulfonates, such as an isomerized alpha olefin sulfonate. The internal olefin sulfonates or isomerized olefin sulfonates may also comprise branching. In certain embodiments, C15-18 IOS may be added to the single-phase liquid surfactant package when the LPS injection fluid is intended for use in high temperature unconventional subterranean formations, such as formations above 130° F. (approximately 55° C.). The IOS may be at least 20% branching, 30% branching, 40% branching, 50% branching, 60% branching, or 65% branching. In some embodiments, the branching is between 20-98%, 30-90%, 40-80%, or around 65%. Examples of internal olefin sulfonates and the methods to make them are found in U.S. Pat. No. 5,488,148, U.S. Patent Application Publication 2009/0112014, and SPE 129766, all incorporated herein by reference.

In embodiments, the anionic surfactant can be a disulfonate, alkyldiphenyloxide disulfonate, mono alkyldiphenyloxide disulfonate, di alkyldiphenyloxide disulfonate, or a di alkyldiphenyloxide monosulfonate, where the alkyl group can be a C6-C36 linear or branched alkyl group. In embodiments, the anionic surfactant can be an alkylbenzene sulfonate or a dibenzene disufonate. In embodiments, the anionic surfactant can be benzenesulfonic acid, decyl(sulfophenoxy)-disodium salt; linear or branched C6-C36 alkyl:PO(0-65):EO(0-100) sulfate; or linear or branched C6-C36 alkyl:PO(0-65):EO(0-100) carboxylate. In embodiments, the anionic surfactant is an isomerized olefin sulfonate (C6-C30), internal olefin sulfonate (C6-C30) or internal olefin disulfonate (C6-C30). In some embodiments, the anionic surfactant is a Guerbet-PO(0-65)-EO(0-100) sulfate (Guerbet portion can be C6-C36). In some embodiments, the anionic surfactant is a Guerbet-PO(0-65)-EO(0-100) carboxylate (Guerbet portion can be C6-C36). In some embodiments, the anionic surfactant is alkyl PO(0-65) and EO(0-100) sulfonate: where the alkyl group is linear or branched C6-C36. In some embodiments, the anionic surfactant is a sulfosuccinate, such as a dialkylsulfosuccinate. In some embodiments, the anionic surfactant is an alkyl aryl sulfonate (AAS) (e.g. an alkyl benzene sulfonate (ABS)), a C10-C30 internal olefin sulfate (IOS), a petroleum sulfonate, or an alkyl diphenyl oxide (di)sulfonate.

In some examples, the anionic surfactant can comprise a surfactant defined by the formula below:

wherein R¹ comprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chain comprising at least one oxide group selected from the group consisting of ethylene oxide, propylene oxide, butylene oxide, and combinations thereof; and R³ comprises a branched or unbranched hydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5 carboxylate groups.

In some examples, the anionic surfactant can comprise a surfactant defined by the formula below:

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and M represents a counterion (e.g., Na⁺, K⁺). In some embodiments, R⁴ is a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-16 carbon atoms.

Example cationic surfactants include surfactant analogous to those described above, except bearing primary, secondary, or tertiary amines, or quaternary ammonium cations, as a hydrophilic head group. “Zwitterionic” or “zwitterion” as used herein refers to a neutral molecule with a positive (or cationic) and a negative (or anionic) electrical charge at different locations within the same molecule. Example zwitterionic surfactants include betains and sultains.

Examples of suitable surfactants are disclosed, for example, in U.S. Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806, 6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837, 9,422,469, 9,605,198, and 9,617,464; WIPO Patent Application Nos. WO/2008/079855, WO/2012/027757 and WO/2011/094442; as well as U.S. Patent Application Nos. 2005/0199395, 2006/0185845, 2006/0189486, 2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175, 2007/0191633, 2010/004843. 2011/0201531, 2011/0190174, 2011/0071057, 2011/0059873, 2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110, and 2017/0198202, each of which is hereby incorporated by reference herein in its entirety for its description of example surfactants.

Optionally, the single-phase liquid surfactant package can include one or more additional components. For example, the single-phase liquid surfactant package can further comprise an acid, a polymer, a friction reducer, a gelling agent, a crosslinker, a scale inhibitor, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a corrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, a wettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, or an alkoxylated C1-C5 alcohol), or any combination thereof.

In some embodiments, the single-phase liquid surfactant package can further include one or more co-solvents. Suitable co-solvents include alcohols, such as lower carbon chain alcohols such as 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)glycol ethers, ethoxylated phenol, or any other common organic co-solvent or combinations of any two or more co-solvents. In one embodiment, the co-solvent can comprise alkyl ethoxylate (C1-C6)-XEO X=1-30-linear or branched. In some embodiments, the co-solvent can comprise ethylene glycol butyl ether (EGBE), diethylene glycol monobutyl ether (DGBE), triethylene glycol monobutyl ether (TEGBE), ethylene glycol dibutyl ether (EGDE), polyethylene glycol monomethyl ether (mPEG), or any combination thereof.

Prior to injection into a well, the single-phase liquid surfactant package is combined with an aqueous-based injection fluid to form an LPS injection fluid. The single-phase liquid surfactant package may be added directly into the aqueous-based injection fluid, or the single-phase liquid surfactant package may be diluted (e.g., with water or an aqueous-based injection fluid) prior to being added to the injection fluid. In embodiments, the aqueous-based injection fluid prior to addition of the single-phase liquid surfactant package is an aqueous-based injection fluid that was previously injected into the well. When added, the single-phase liquid surfactant package can decrease the particle size distribution within the aqueous-based injection fluid, creating an LPS injection fluid.

In example embodiments, the aqueous-based injection fluid can comprise any type of water, treated or untreated, and can vary in salt content. For example, the water can include sea water, brackish water, flowback or produced water, wastewater (e.g., reclaimed or recycled), brine (e.g., reservoir brine, formation brine, and/or synthetic brine), fresh water (e.g., fresh water comprises <1,000 ppm TDS water), or any combination thereof. In some embodiments, the water can comprise a formation brine produced from the unconventional subterranean formation, such as any reservoir brine present within the unconventional subterranean formation. In certain examples, the water can include hard water or hard brine. In some embodiments, the water can include at least 10 ppm of divalent metal ions (e.g., at least 100 ppm, at least 500 ppm, at least 1,000 ppm, at least 5,000 ppm, at least 10,000 ppm, at least 20,000 ppm, or at least 30,000 ppm). In some embodiments, the water can include 30,000 ppm or less of divalent metal ions (e.g., 20,000 ppm or less, 10,000 ppm or less, 5,000 ppm or less, 1,000 ppm or less, 500 ppm or less, 100 ppm or less, or 50 ppm or less). In certain embodiments, the from 10 ppm to 30,000 ppm of divalent metal ions.

The water can have a concentration of divalent metal ions ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the water can include from 10 ppm to 30,000 ppm of divalent metal ions (e.g., from 50 ppm to 30,000 ppm, from 100 ppm to 30,000 ppm, from 500 ppm to 30,000 ppm, from 1000 ppm to 30,000 ppm, from 5000 ppm to 30,000 ppm, from 10,000 ppm to 30,000 ppm, from 20,000 ppm to 30,000 ppm, from 10 ppm to 20,000 ppm, from 50 ppm to 20,000 ppm, from 100 ppm to 20,000 ppm, from 500 ppm to 20,000 ppm, from 1000 ppm to 20,000 ppm, from 5000 ppm to 20,000 ppm, from 10,000 ppm to 20,000 ppm, from 10 ppm to 10,000 ppm, from 50 ppm to 10,000 ppm, from 100 ppm to 10,000 ppm, from 500 ppm to 10,000 ppm, from 1000 ppm to 10,000 ppm, from 5000 ppm to 10,000 ppm, from 10 ppm to 5,000 ppm, from 50 ppm to 5,000 ppm, from 100 ppm to 5,000 ppm, from 500 ppm to 5,000 ppm, from 1000 ppm to 5,000 ppm, from 10 ppm to 1,000 ppm, from 50 ppm to 1,000 ppm, from 100 ppm to 20,000 ppm, from 500 ppm to 1,000 ppm, from 10 ppm to 500 ppm, from 50 ppm to 500 ppm, from 100 ppm to 500 ppm, from 10 ppm to 100 ppm, from 50 ppm to 100 ppm, or from 10 ppm to 50 ppm).

In some embodiments, the divalent metal ions can be chosen from Ca²⁺, Mg²⁺, Sr²⁺, and Ba²⁺, or any combination thereof.

In some embodiments, the water can have salinity of at least 5,000 ppm TDS (e.g., at least 10,000 ppm TDS, at least 20,000 ppm TDS, at least 30,000 ppm TDS, at least 50,000 ppm TDS, at least 75,0000 ppm TDS, at least 100,000 ppm TDS, at least 150,000 ppm TDS, at least 200,000 ppm TDS, at least 250,000 ppm TDS, or at least 275,000 ppm TDS). In some embodiments, the water can have a salinity of 300,000 ppm TDS or less (e.g., 275,000 ppm TDS or less, 250,000 ppm TDS or less, 200,000 ppm TDS or less, 150,000 ppm TDS or less, 100,000 ppm TDS or less, 50,000 ppm TDS or less, 30,000 ppm TDS or less, 25,000 ppm TDS or less, 20,000 ppm TDS or less, 15,000 ppm TDS or less, or 10,000 ppm TDS or less).

The water can have a salinity ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the water can have a salinity of at least 5,000 ppm TDS to 300,000 ppm TDS, such as a salinity of from 5,000 ppm TDS to 10,000 ppm TDS, from 5,000 ppm TDS to 15,000 ppm TDS, from 5,000 ppm TDS to 30,000 ppm TDS, from 5,000 ppm TDS to 50,000 ppm TDS, from 5,000 ppm TDS to 100,000 ppm TDS, from 5,000 ppm TDS to 150,000 ppm TDS, from 5,000 ppm TDS to 200,000 ppm TDS, from 5,000 ppm TDS to 250,000 ppm TDS, from 5,000 ppm TDS to 300,000 ppm TDS, from 15,000 ppm TDS to 30,000 ppm TDS, from 15,000 ppm TDS to 50,000 ppm TDS, from 15,000 ppm TDS to 100,000 ppm TDS, from 15,000 ppm TDS to 150,000 ppm TDS, from 15,000 ppm TDS to 200,000 ppm TDS, from 15,000 ppm TDS to 250,000 ppm TDS, from 15,000 ppm TDS to 300,000 ppm TDS, from 20,000 ppm TDS to 50,000 ppm TDS, from 20,000 ppm TDS to 100,000 ppm TDS, from 20,000 ppm TDS to 150,000 ppm TDS, from 20,000 ppm TDS to 200,000 ppm TDS, from 20,000 ppm TDS to 250,000 ppm TDS, from 20,000 ppm TDS to 300,000 ppm TDS, from 25,000 ppm TDS to 50,000 ppm TDS, from 25,000 ppm TDS to 100,000 ppm TDS, from 25,000 ppm TDS to 150,000 ppm TDS, from 25,000 ppm TDS to 200,000 ppm TDS, from 25,000 ppm TDS to 250,000 ppm TDS, from 25,000 ppm TDS to 300,000 ppm TDS, from 50,000 ppm TDS to 100,000 ppm TDS, from 50,000 ppm TDS to 150,000 ppm TDS, from 50,000 ppm TDS to 200,000 ppm TDS, from 50,000 ppm TDS to 250,000 ppm TDS, from 50,000 ppm TDS to 300,000 ppm TDS, from 100,000 ppm TDS to 150,000 ppm TDS, from 100,000 ppm TDS to 200,000 ppm TDS, from 100,000 ppm TDS to 250,000 ppm TDS, from 100,000 ppm TDS to 300,000 ppm TDS, from 150,000 ppm TDS to 200,000 ppm TDS, from 150,000 ppm TDS to 250,000 ppm TDS, from 150,000 ppm TDS to 300,000 ppm TDS, from 200,000 ppm TDS to 250,000 ppm TDS, from 200,000 ppm TDS to 300,000 ppm TDS, or from 250,000 ppm TDS to 300,000 ppm TDS. In some embodiments, the aqueous-based injection fluid can comprise slickwater.

The LPS injection fluids can comprise from 30% to 99.85% by weight of the total composition of water, for example from 70% to 98% water.

In some embodiments, the aqueous-based injection fluid can include an acid, a polymer, a friction reducer, a gelling agent, a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, an iron control agent, a scale inhibitor, a corrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, a wettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, or an alkoxylated C1-C5 alcohol), or any combination thereof. In certain embodiments, the aqueous-based injection fluid can comprise an acid (e.g., at least 10% acid, such as from 10% to 20% by weight acid). In certain embodiments, the injection fluid can comprise a proppant.

Once combined with the aqueous-based injection fluid, the primary surfactant can have a concentration within the low particle size injection fluid of at least 0.01% by weight (e.g., at least 0.02% by weight, at least 0.03% by weight, at least 0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, at least 0.07% by weight, at least 0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2% by weight, at least 0.25% by weight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, at least 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, at least 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9% by weight, at least 0.95% by weight, at least 1% by weight, at least 1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, at least 2% by weight, or at least 2.25% by weight), based on the total weight of the low particle size injection fluid. In some embodiments, the primary surfactant can have a concentration within the low particle size injection fluid of 2.5% by weight or less (e.g., 2.25% by weight or less, 2% by weight or less, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weight or less, 1% by weight or less, 0.95% by weight or less, 0.9% by weight or less, 0.85% by weight or less, 0.8% by weight or less, 0.75% by weight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45% by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3% by weight or less, 0.25% by weight or less, 0.2% by weight or less, 0.15% by weight or less, 0.1% by weight or less, 0.09% by weight or less, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weight or less, 0.05% by weight or less, 0.04% by weight or less, 0.03% by weight or less, or 0.02% by weight or less), based on the total weight of the LPS injection fluid. In particular embodiments, the primary surfactant can have a concentration within the low particle size injection fluid of less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, or less than 0.05%.

The primary surfactant can have a concentration within the low particle size injection fluid ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the primary surfactant can have a concentration within the low particle size injection fluid of from 0.01% to 2.5% by weight (e.g., from 0.01% to 0.05% by weight, from 0.01% to 0.1% by weight, from 0.01% to 0.5% by weight, from 0.01% to 0.75% by weight, from 0.01% to 1% by weight, from 0.01% to 1.5% by weight, from 0.01% to 2% by weight, from 0.05% to 0.1% by weight, from 0.05% to 0.5% by weight, from 0.05% to 1% by weight, from 0.05% to 1.5% by weight, from 0.05% to 2% by weight, from 0.05% to 2.5% by weight, from 0.1% to 0.5% by weight, from 0.1% to 1% by weight, from 0.1% to 1.5% by weight, from 0.1% to 2% by weight, from 0.1% to 2.5% by weight, from 0.5% to 1% by weight, from 0.5% to 1.5% by weight, from 0.5% to 2% by weight, from 0.5% to 2.5% by weight, from 1% to 1.5% by weight, from 1% to 2% by weight, from 1% to 2.5% by weight, from from 1.5% to 2% by weight, from 1.5% to 2.5% by weight, or from 2% to 2.5% by weight), based on the total weight of the low particle size injection fluid.

When present, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of at least 0.001% by weight (e.g., at least 0.005% by weight, at least 0.01% by weight, at least 0.02% by weight, at least 0.03% by weight, at least 0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, at least 0.07% by weight, at least 0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2% by weight, at least 0.25% by weight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, at least 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, at least 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9% by weight, at least 0.95% by weight, at least 1% by weight, at least 1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, at least 2% by weight, or at least 2.25% by weight), based on the total weight of the low particle size injection fluid. In some embodiments, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of 2.5% by weight or less (e.g., 2.25% by weight or less, 2% by weight or less, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weight or less, 1% by weight or less, 0.95% by weight or less, 0.9% by weight or less, 0.85% by weight or less, 0.8% by weight or less, 0.75% by weight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45% by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3% by weight or less, 0.25% by weight or less, 0.2% by weight or less, 0.15% by weight or less, 0.1% by weight or less, 0.09% by weight or less, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weight or less, 0.05% by weight or less, 0.04% by weight or less, 0.03% by weight or less, 0.02% by weight or less, 0.01% by weight or less, or 0.005% by weight or less), based on the total weight of the LPS injection fluid. In particular embodiments, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of less than 2%, less than 1.5%, less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, less than 0.05%, or less than 0.01%.

When present, the one or more secondary surfactants can have a concentration within the low particle size injection fluid ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the one or more secondary surfactants can have a concentration within the low particle size injection fluid of from 0.001% to 2.5% by weight (e.g., from 0.001% to 2% by weight, from 0.001% to 1.5% by weight, from 0.001% to 1% by weight, from 0.001% to 0.5% by weight, from 0.001% to 0.1% by weight, from 0.001% to 0.05% by weight, from 0.001% to 0.01% by weight, from 0.01% to 2.5% by weight, from 0.01% to 2% by weight, from 0.01% to 1.5% by weight, from 0.01% to 1% by weight, from 0.01% to 0.5% by weight, from 0.01% to 0.1% by weight, from 0.01% to 0.05% by weight, from 0.05% to 2.5% by weight, from 0.05% to 2% by weight, from 0.05% to 1.5% by weight, from 0.05% to 1% by weight, from 0.05% to 0.5% by weight, from 0.05% to 0.1% by weight, from 0.1% to 2.5% by weight, from 0.1% to 2% by weight, from 0.1% to 1.5% by weight, from 0.1% to 1% by weight, from 0.1% to 0.5% by weight, from 0.5% to 2.5% by weight, from 0.5% to 2% by weight, from 0.5% to 1.5% by weight, from 0.5% to 1% by weight, from 1% to 2.5% by weight, from 1% to 2% by weight, from 1% to 1.5% by weight, from 1.5% to 2.5% by weight, from 1.5% to 2% by weight, or from 2% to 2.5% by weight), based on the total weight of the low particle size injection fluid.

In some embodiments, the primary surfactant and one or more secondary surfactants can be present in the LPS injection fluid, the single-phase liquid surfactant package, or both in a weight ratio of primary surfactant to one or more secondary surfactants of at least 1:1 (e.g., at least 2:1, at least 2.5:1, at least 3:1, at least 4:1, at least 5:1, at least 6:1, at least 7:1, at least 8:1, or at least 9:1). In some embodiments, the primary surfactant and one or more secondary surfactants can be present in the LPS injection fluid, the single-phase liquid surfactant package, or both in a weight ratio of primary surfactant to one or more secondary surfactants of 10:1 or less (e.g., 9:1 or less; 8:1 or less, 7:1 or less, 6:1 or less, 5:1 or less, 4:1 or less, 3:1 or less, 2.5:1 or less, or 2:1 or less).

The primary surfactant and one or more secondary surfactants can be present in the LPS injection fluid, the single-phase liquid surfactant package, or both in a weight ratio ranging from any of the minimum values described above to any of the maximum values described above. For example, the primary surfactant and one or more secondary surfactants can be present in the LPS injection fluid, the single-phase liquid surfactant package, or both in a weight ratio of primary surfactant to one or more secondary surfactants of from 1:1 to 10:1 (e.g., from 1:1 to 5:1, from 2:1, or from 3:1).

In other embodiments, the one or more secondary surfactants are absent (i.e., the primary surfactant is the only surfactant present in the single-phase liquid surfactant package).

In some embodiments, the total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can be at least 0.01% by weight (e.g., at least 0.02% by weight, at least 0.03% by weight, at least 0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, at least 0.07% by weight, at least 0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2% by weight, at least 0.25% by weight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, at least 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, at least 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9% by weight, at least 0.95% by weight, at least 1% by weight, at least 1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, at least 2% by weight, at least 2.25% by weight, at least 2.5% by weight, at least 2.75% by weight, at least 3% by weight, at least 3.25% by weight, at least 3.5% by weight, at least 3.75% by weight, at least 4% by weight, at least 4.25% by weight, at least 4.5% by weight, or at least 4.75% by weight), based on the total weight of the LPS injection fluid. In some embodiments, the total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can be 5% by weight or less (e.g., 4.75% by weight or less, 4.5% by weight or less, 4.25% by weight or less, 4% by weight or less, 3.75% by weight or less, 3.5% by weight or less, 3.25% by weight or less, 3% by weight or less, 2.75% by weight or less, 2.5% by weight or less, 2.25% by weight or less, 2% by weight or less, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weight or less, 1% by weight or less, 0.95% by weight or less, 0.9% by weight or less, 0.85% by weight or less, 0.8% by weight or less, 0.75% by weight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45% by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3% by weight or less, 0.25% by weight or less, 0.2% by weight or less, 0.15% by weight or less, 0.1% by weight or less, 0.09% by weight or less, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weight or less, 0.05% by weight or less, 0.04% by weight or less, 0.03% by weight or less, or 0.02% by weight or less), based on the total weight of the LPS injection fluid.

The total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can range from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can be from 0.01% by weight to 5% by weight (e.g., from 0.01% to 2.5% by weight, from 0.01% to 1% by weight, from 0.01% to 0.5% by weight, from 0.01% to 0.1% by weight, from 0.01% to 0.05% by weight, from 0.05% by weight to 5% by weight, from 0.05% to 2.5% by weight, from 0.05% to 1% by weight, from 0.05% to 0.5% by weight, from 0.05% to 0.1% by weight, from 0.1% by weight to 5% by weight, from 0.1% to 2.5% by weight, from 0.1% to 1% by weight, from 0.1% to 0.5% by weight, from 0.5% by weight to 5% by weight, from 0.5% to 2.5% by weight, from 0.5% to 1% by weight, from 1% by weight to 5% by weight, from 1% to 2.5% by weight, from 1% to 2% by weight, from 2% by weight to 5% by weight, from 2% to 2.5% by weight, or from 2.5% by weight to 5% by weight).

In some embodiments when the LPS injection fluid is being injected into a horizontal well, the total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can be from 0.01% to 1.5% by weight, from 0.01% to 1% by weight, or from 0.01% to 0.5% by weight).

In some embodiments when the LPS injection fluid is being injected into a vertical well, the total concentration of all surfactants in the LPS injection fluid (the total concentration of the primary surfactant and the one or more secondary surfactants in the LPS injection fluid) can be from 0.01% to 5% by weight, from 0.01% to 1% by weight, from 0.5% to 5% by weight, from 0.5% to 2.5% by weight, from 0.5% to 1.5% by weight, from 0.5% to 1% by weight, from 1% to 5% by weight, from 1% to 2.5% by weight, from or 1% to 1.5% by weight).

When present, the one or more co-solvents can have a concentration within the low particle size injection fluid of less than 2%, less than 1.5%, less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, less than 0.05%, or less than 0.01%. For example, the one or more co-solvents can have a concentration within the low particle size injection fluid of from 0.001% to 1.5% by weight (e.g., from 0.001% to 1% by weight, from 0.001% to 0.5% by weight, from 0.001% to 0.05% by weight, from 0.001% to 0.01% by weight, from 0.05% to 1.5% by weight, from 0.05% to 1% by weight, from 0.05% to 0.5% by weight, from 0.05% to 0.1% by weight, from 0.01% to 1.5% by weight, from 0.01% to 1% by weight, from 0.01% to 0.5% by weight, from 0.01% to 0.05% by weight, from 0.1% to 1.5% by weight, from 0.1% to 1% by weight, from 0.1% to 0.5% by weight, or from 1% to 1.5% by weight), based on the total weight of the low particle size injection fluid.

After the single-phase liquid surfactant package has been combined with the aqueous-based injection fluid, the LPS injection fluid may be a single-phase fluid or may be an emulsion depending on the amount of oil within the injection fluid.

In some embodiments, the single-phase liquid surfactant package (and by extension the LPS injection fluid) can comprise a non-ionic surfactant and an anionic surfactant (e.g., a sulfonate or disulfonate). In some embodiments, the single-phase liquid surfactant package (and by extension the LPS injection fluid) can comprise a non-ionic surfactant and two or more anionic surfactants (e.g., a sulfonate or disulfonate and a carboxylate). In some embodiments, the single-phase liquid surfactant package (and by extension the LPS injection fluid) can comprise a non-ionic surfactant (e.g., a C6-C16 alkyl phenol ethoxylate, or a C6-C16:PO(0-25):EO(0-25), such as a C9-C11 ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylated propoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol) and a sulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS). In some embodiments, the single-phase liquid surfactant package (and by extension the LPS injection fluid) can comprise a non-ionic surfactant (e.g., a C6-C16 alkyl phenol ethoxylate, or a C6-16:PO(0-25):EO(0-25), such as a C9-C11 ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylated propoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol), a sulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS), and a carboxylate surfactant (e.g., a C10-16 alkyl polyglucoside carboxylate or a C22-C36 Guerbet alkoxylated carboxylate).

Specific example embodiments include the LPS injection fluids in the table below.

LPS
Injection	Surfactants and Co-Surfactants in LPS
Fluid	Injection Fluid (in weight percent)

1	0.09% alkoxylated C6-C16 alcohol
	0.06% disulfonate
2	0.1% alkoxylated C6-C16 alcohol
	0.1% carboxylate
	0.1% disulfonate
3	0.15% alkoxylated C6-C16 alcohol
	0.075% carboxylate
	0.075% disulfonate
4	0.2% alkoxylated C6-C16 alcohol
	0.1% carboxylate
5	0.2% alkoxylated C6-C16 alcohol
	0.033% carboxylate
	0.066% disulfonate
6	0.2% alkoxylated C6-C16 alcohol
	0.033% carboxylate
	0.066% disulfonate
7	0.2% alkoxylated C6-C16 alcohol
	0.05% carboxylate
	0.05% olefin sulfonate
8	0.15% alkoxylated C6-C16 alcohol
	0.05% carboxylate
	0.05% olefin sulfonate
	0.05% alkyl polyglucoside
9	0.1% alkoxylated C6-C16 alcohol
	0.05% carboxylate
	0.05% olefin sulfonate
	0.1% alkyl polyglucoside
10	0.15% alkoxylated C6-C16 alcohol
	0.07% carboxylate
	0.03% olefin sulfonate
	0.1% alkyl polyglucoside
11	0.1% alkoxylated C6-C16 alcohol
	0.04% carboxylate
	0.05% olefin sulfonate
	0.03% disulfonate
	0.1% alkyl polyglucoside
12	0.1% alkoxylated C6-C16 alcohol
	0.04% carboxylate
	0.06% disulfonate
	0.1% alkyl polyglucoside
13	0.15% alkoxylated C6-C16 alcohol
	0.15% alkoxylated alkylphenol
	0.1% olefin sulfonate
	0.1% Guerbet alkoxylated carboxylate
14	0.125% alkoxylated C6-C16 alcohol
	0.175% alkoxylated alkylphenol
	0.1% olefin sulfonate
	0.1% Guerbet alkoxylated carboxylate
15	0.1% alkoxylated C6-C16 alcohol
	0.2% alkoxylated alkylphenol
	0.1% olefin sulfonate
	0.1% Guerbet alkoxylated carboxylate
16	0.12% alkoxylated C6-C16 alcohol
	0.22% alkoxylated alkylphenol
	0.08% olefin sulfonate
	0.08% Guerbet alkoxylated carboxylate
17	0.15% alkoxylated C6-C16 alcohol
	0.15% alkoxylated alkylphenol
	0.08% olefin sulfonate
	0.06% Guerbet alkoxylated carboxylate
	0.06% carboxylate
18	0.15% alkoxylated C6-C16 alcohol
	0.15% alkoxylated alkylphenol
	0.05% olefin sulfonate
	0.1% Guerbet alkoxylated carboxylate
	0.05% disulfonate
19	0.5% olefin sulfonate
	0.5% Guerbet alkoxylated carboxylate
	0.55% glycosides or glucosides
20	0.5% olefin sulfonate
	0.5% Guerbet alkoxylated carboxylate
	0.5% glycosides or glucosides
	0.25% alkoxylated C6-C16 alcohol
21	0.5% olefin sulfonate
	0.5% Guerbet alkoxylated carboxylate
	0.5% glycosides or glucosides
	0.5% alkoxylated C6-C16 alcohol
22	0.5% olefin sulfonate
	0.5% Guerbet alkoxylated carboxylate
	1% glycosides or glucosides
	0.5% alkoxylated C6-C16 alcohol
23	0.05% olefin sulfonate
	0.05% Guerbet alkoxylated carboxylate
	0.05% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
24	0.075% glycosides or glucosides
	0.075% alkoxylated C6-C16 alcohol
25	0.1% alkoxylated C6-C16 alcohol
	0.05% disulfonate
26	0.1% alkoxylated C6-C16 alcohol
	0.05% disulfonate
	0.03% hydroxyalkyl alkylammonium chloride
27	0.03% olefin sulfonate
	0.04% Guerbet alkoxylated carboxylate
	0.08% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
28	0.4% olefin sulfonate
	0.4% Guerbet alkoxylated carboxylate
	0.7% glycosides or glucosides
	0.5% alkoxylated C6-C16 alcohol
29	0.05% olefin sulfonate
	0.1% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
30	0.05% olefin sulfonate
	0.1% alkyl polyglucoside
	0.05% alkoxylated C6-C16 alcohol
31	0.05% olefin sulfonate
	0.1% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
32	0.05% olefin sulfonate
	0.1% alkyl polyglucoside
	0.05% alkoxylated C6-C16 alcohol
33	0.05% olefin sulfonate
	0.1% alkyl polyglucoside
	0.05% alkoxylated C6-C16 alcohol
34	0.05% olefin sulfonate
	0.05% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
	0.05% carboxylate
35	0.05% olefin sulfonate
	0.05% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
	0.05% carboxylate
36	0.05% olefin sulfonate
	0.05% alkyl polyglucoside
	0.05% alkoxylated C6-C16 alcohol
37	0.06% olefin sulfonate
	0.05% alkyl polyglucoside
	0.04% alkoxylated C6-C16 alcohol
38	0.04% olefin sulfonate
	0.08% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
	0.03% disulfonate
39	0.035% olefin sulfonate
	0.075% glycosides or glucosides
	0.05% alkoxylated C6-C16 alcohol
	0.04% disulfonate
40	0.035% olefin sulfonate
	0.07% glycosides or glucosides
	0.045% alkoxylated C6-C16 alcohol
	0.05% disulfonate
41	0.1% alkoxylated C6-C16 alcohol
	0.1% disulfonate
42	0.25% Guerbet alkoxylated carboxylate
	0.25% olefin sulfonate
	0.5% glycosides or glucosides
	0.5% co-solvent
43	0.075% alkoxylated C12-C22 alcohol
	0.075% disulfonate
44	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
45	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
46	0.075% alkoxylated C6-C16 alcohol
	0.075% disulfonate
47	0.075% disulfonate
	0.075% alkoxylated C6-C16 alcohol
48	0.0625% disulfonate
	0.0875% alkoxylated C6-C16 alcohol
49	0.055% disulfonate
	0.095% alkoxylated C6-C16 alcohol
50	0.075% disulfonate
	0.075% alkoxylated C6-C16 alcohol
51	1% alkoxylated C6-C16 alcohol
	0.5% disulfonate
52	1% alkoxylated C6-C16 alcohol
53	1% alkoxylated C6-C16 alcohol
	2.25% sulfosuccinate
54	0.25% Guerbet alkoxylated carboxylate
	1% alkoxylated C6-C16 alcohol
	2.25% sulfosuccinate
55	0.25% Guerbet alkoxylated carboxylate
	1% alkoxylated alkylphenol
	2.25% sulfosuccinate
56	0.25% Guerbet alkoxylated carboxylate
	1% alkoxylated C6-C16 alcohol
57	0.25 Guerbet alkoxylated carboxylate
	1% alkoxylated alkylphenol
58	0.65% carboxylate
	0.35% alkoxylated C6-C16 alcohol
59	0.325% carboxylate
	0.925% alkoxylated C6-C16 alcohol
60	0.25% olefin sulfonate
	1.0% alkoxylated C6-C16 alcohol
61	0.15% olefin sulfonate
	0.2% Guerbet alkoxylated carboxylate
	0.92% carboxylate
62	0.65% carboxylate
	0.35% second carboxylate
63	0.65% carboxylate
	0.35% alkoxylated C6-C16 alcohol
	1% olefin sulfonate
64	1% alkoxylated alcohol
	1% olefin sulfonate
65	0.5% alkoxylated alcohol
	0.5% olefin sulfonate
	0.25% carboxylate
66	0.6% co-solvent
	0.6% olefin sulfonate
67	0.6% co-solvent
	0.3% disulfonate
	0.3% olefin sulfonate
68	0.6% Guerbet alkoxylated carboxylate
	0.6% disulfonate
69	0.6% co-solvent
	0.4% disulfonate
	0.2% olefin sulfonate
70	0.5% alkoxylated C6-C16 alcohol
	0.4% disulfonate
	0.3% olefin sulfonate
71	1% alkoxylated C6-C16 alcohol
72	0.9% alkoxylated C6-C16 alcohol
	0.6% disulfonate
73	0.4% alkoxylated C6-C16 alcohol
	0.35% disulfonate
	0.25% olefin sulfonate
	0.5% co-solvent
74	0.25% Guerbet alkoxylated carboxylate
	0.5% alkoxylated C6-C16 alcohol
	0.35% disulfonate
	0.15% olefin sulfonate
	0.35% co-solvent
75	0.25% Guerbet alkoxylated carboxylate
	0.25% alkoxylated C6-C16 alcohol
	0.25% olefin sulfonate
	0.25% co-solvent
76	0.25% Guerbet alkoxylated carboxylate
	0.25% alkoxylated C6-C16 alcohol
	0.25% olefin sulfonate
	0.25% alkoxylated alcohol
77	0.25% Guerbet alkoxylated carboxylate
	0.35% olefin sulfonate
	0.5% alkoxylated alcohol
78	0.25% Guerbet alkoxylated carboxylate
	0.25% alkoxylated C6-C16 alcohol
	0.15% olefin sulfonate
	0.1% disulfonate
	0.25% co-solvent
79	0.25% Guerbet alkoxylated carboxylate
	0.25% alkoxylated C6-C16 alcohol
	0.25% olefin sulfonate
	0.25% glycosides or glucosides
	0.25% co-solvent
	0.15% disulfonate
80	0.25% Guerbet alkoxylated carboxylate
	0.25% olefin sulfonate
	0.5% glycosides or glucosides
	0.25% co-solvent
81	0.15% alkoxylated C12-C22 alcohol
82	0.075% alkoxylated C12-C22 alcohol
	0.075% disulfonate
83	0.075% alkoxylated C12-C22 alcohol
	0.075% disulfonate
84	0.075% alkoxylated C12-C22 alcohol
	0.075% alkoxylated C6-C16 Guerbet alcohol
85	0.15% alkoxylated C6-C16 Guerbet alcohol
86	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
87	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
	0.05% co-solvent
88	0.1% alkoxylated C6-C16 alcohol
	0.05% disulfonate
89	1% alkoxylated C6-C16 alcohol
	0.5% disulfonate
90	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
91	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.125% disulfonate
92	0.075% alkoxylated C12-C22 alcohol
	0.125% disulfonate
93	0.075% alkoxylated C12-C22 alcohol
	0.075% disulfonate
94	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
95	0.1% alkoxylated C6-C16 Guerbet alcohol
	0.05% disulfonate
96	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
97	0.075% alkoxylated C6-C16 alcohol
	0.075% disulfonate
98	0.075% alkoxylated C6-C16 Guerbet alcohol
	0.075% disulfonate
99	0.1% alkoxylated C6-C16 alcohol
	0.05% disulfonate
100	0.09% alkoxylated C6-C16 alcohol
	0.06% disulfonate
101	0.1% alkoxylated C6-C16 alcohol
	0.1% disulfonate
	0.1% Guerbet alkoxylated carboxylate
102	0.1% alkoxylated C6-C16 alcohol
	0.1% disulfonate
103	0.65% Guerbet alkoxylated carboxylate
	0.35% olefin sulfonate
	0.33% alkoxylated alkylphenol
	0.5% co-solvent
	0.25% second co-solvent
104	0.075% alkoxylated C6-C16 alcohol
	0.075% benzenesulfonic acid, decyl(sulfophenoxy)-
	disodium salt
105	0.15% alkoxylated C6-C16 alcohol
	0.05% benzenesulfonic acid, decyl(sulfophenoxy)-
	disodium salt

In some embodiments, the primary surfactant and the one or more secondary surfactants can be added to the aqueous-based injection fluid to form the LPS injection fluid. For example, the primary surfactant and the one or more secondary surfactants can be pre-mixed as components of the single-phase liquid surfactant package. Alternatively, the primary surfactant and the one or more secondary surfactants can be separately combined with (e.g., sequentially added to) the aqueous-based injection fluid to form the LPS injection fluid. In other embodiments, the primary surfactant and/or the one or more secondary surfactants can be added separately or together to an aqueous-based injection fluid when preparing slickwater in a tank. In some embodiments, the primary surfactant and the one or more secondary surfactants can be mixed with one or more additional components prior to combination with the aqueous-based injection fluid.

The one or more surfactants present in the single-phase liquid surfactant package (and ultimately the LPS injection fluid) can be selected to improve hydrocarbon recovery. Specifically, the one or more surfactants can improve hydrocarbon recovery by increasing the aqueous stability of the LPS injection fluid at the temperature and salinity of the reservoir, decreasing the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the reservoir, changing (e.g., increasing or decreasing the wettability of the reservoir, or any combination thereof.

In some embodiments, the one or more surfactants in the single-phase liquid surfactant package (and ultimately the LPS injection fluid) can increase the aqueous stability of the LPS injection fluid at the temperature and salinity of the reservoir. Aqueous stable solutions can propagate further into a reservoir upon injection as compared to an injection fluid lacking aqueous stability. In addition, because injected chemicals remain soluble aqueous stable solutions, aqueous stable solutions do not precipitate particulates or phase separate within the formation which may obstruct or hinder fluid flow through the reservoir. As such, injection fluids that exhibit aqueous stability under reservoir conditions can largely eliminate formation damage associated with precipitation of injected chemicals. In this way, hydrocarbon recovery can be facilitated by the one or more surfactants in the single-phase liquid surfactant package.

In some embodiments, the one or more surfactants in the single-phase liquid surfactant package (and ultimately the LPS injection fluid) can decrease the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the reservoir. Reducing the IFT can decrease pressure required to drive an aqueous-based injection fluid into the formation matrix. In addition, decreasing the IFT reduces water block during production, facilitating the flow of hydrocarbons from the formation to the wellbore (e.g., facilitating the flow of hydrocarbons back through the fractures and to the wellbore). In this way, hydrocarbon recovery can be facilitated by the one or more surfactants in the single-phase liquid surfactant package.

In some embodiments, the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the formation can be of 2 or less (e.g., 1.5 or less, 1 or less, 0.5 or less, or 0.1 or less).

In some embodiments, the one or more surfactants in the single-phase liquid surfactant package (and ultimately the LPS injection fluid) can change the wettability of the reservoir. In particular, in embodiments where the reservoir is oil-wet or mixed-wet, the one or more surfactants in the single-phase liquid surfactant package (and ultimately the LPS injection fluid) can make the reservoir more water-wet. By increasing the water-wetness of the reservoir, the formation will imbibe injected aqueous-based injection fluid into the formation matrix, leading to a corresponding flow of hydrocarbon from regions within the formation back to the fracture. In this way, hydrocarbon recovery can be facilitated by the one or more surfactants in the single-phase liquid surfactant package.

In some embodiments, the one or more surfactants can improve hydrocarbon recovery by increasing the aqueous stability of the LPS injection fluid at the temperature and salinity of the reservoir and decreasing the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the reservoir. In some embodiments, the one or more surfactants can improve hydrocarbon recovery by decreasing the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the reservoir and increasing the wettability of the reservoir. In some embodiments, the one or more surfactants can improve hydrocarbon recovery by increasing the aqueous stability of the LPS injection fluid at the temperature and salinity of the reservoir and increasing the wettability of the reservoir. In certain embodiments, the one or more surfactants can improve hydrocarbon recovery by increasing the aqueous stability of the LPS injection fluid at the temperature and salinity of the reservoir, decreasing the interfacial tension (IFT) of the LPS injection fluid with hydrocarbons in the reservoir, and changing the wettability of the reservoir.

In some embodiments, the combination of the single-phase liquid surfactant package with the aqueous-based injection fluid lowers the particle size distribution of the aqueous-based injection fluid when measured at the temperature and salinity of the subterranean formation.

In some embodiments, the low particle size injection fluid further includes a proppant. In some embodiments, the maximum particle size of less than 0.1 micrometers is exclusive of the proppant. In some embodiments, the low particle size injection fluid is substantially free of proppant.

In some embodiments, the mean particle size distribution of the low particle size injection fluid is less than an average pore size of a rock matrix in the unconventional subterranean formation. In some embodiments, the mean particle size distribution of the low particle size injection fluid is less than 0.05 micrometer in diameter when measured at the temperature and salinity of the unconventional subterranean formation. In some embodiments, the aqueous-based injection fluid has a mean particle size distribution of greater than 10 micrometers prior to the addition of the single-phase liquid surfactant package. In some embodiments, the mean particle size distribution of the low particle size injection fluid is at least 10 micrometers smaller than a mean particle size distribution of the aqueous-based injection fluid. In some embodiments, the low particle size injection fluid precipitates out fewer solid particles than the aqueous-based injection fluid when injected into the rock matrix.

Methods

Described herein are methods for treating an unconventional subterranean formation with a fluid, the method including: (a) combining a single-phase liquid surfactant package including a primary surfactant with an aqueous-based injection fluid to form a low particle size injection fluid; (b) injecting the low particle size injection fluid into a primary wellbore in fluid communication with the unconventional formation and fluidly connected with a plurality of secondary wellbores; (c) allowing the low particle size injection fluid to contact the unconventional subterranean formation for a period of time; and (d) producing fluid from the unconventional subterranean formation through a plurality of secondary wellbores.

In some embodiments, the primary surfactant can include an anionic surfactant, a non-ionic surfactant, or any combination there including a hydrophobic tail including from 6 to 60 carbon atoms.

The LPS injection fluid can be used during any portion (or during the entirety of) a treatment operation. In some embodiments, the method includes a stimulation operation.

The low particle size injection fluid can have a maximum particle size of less than 0.1 micrometers in diameter in particle size distribution measurements performed at a temperature and salinity of the unconventional subterranean formation.

In some embodiments, the method can further include ceasing injection of the low particle size injection fluid into the primary wellbore before allowing step.

In some embodiments, a method, wherein the allowing step includes contacting the low particle size injection fluid with a rock matrix of the unconventional subterranean formation for a period of time.

In some embodiments, the method comprises producing fluid from the unconventional subterranean formation through one or more secondary wellbores in fluid communication with the primary wellbore during the injecting step (b), during the allowing step (c), after a conclusion of the allowing step (c), or any combination thereof. In certain embodiments, the method comprises producing fluid from the unconventional subterranean formation through one or more secondary wellbores in fluid communication with the primary wellbore during the injecting step (b), during the allowing step (c), and after a conclusion of the allowing step (c).

In some embodiments, the method further comprises monitoring the fluid produced through the one or more secondary wellbores. Monitoring the fluid produced through the one or more secondary wellbores can comprise monitoring the water content of the fluid produced through the one or more secondary wellbores, monitoring for components of the low particle size injection fluid in the fluid produced through the one or more secondary wellbores, monitoring for signs of emulsion and/or foaming in the fluid produced through the one or more secondary wellbores, monitoring for changes in wellhead and/or bottom-hole production pressure in the one or more secondary wellbores, or any combination thereof. In some embodiments, upon observing an increase in the water content of the fluid produced through the one or more secondary wellbore, an increase in a concentration of a component of the low particle size injection fluid in the fluid produced through the one or more secondary wellbores, an increase in emulsion and/or foaming in the fluid produced through the one or more secondary wellbores, an increase in wellhead and/or bottom-hole production pressure in the one or more secondary wellbores, or any combination thereof during the injecting step (b) or during the allowing step (c), the method further comprises temporarily shutting in (ceasing production from) the one or more secondary wellbores.

In some embodiments, injecting step (b) comprises injecting a volume of the low particle size injection fluid equal to from 10% to 250% (e.g., from 25% to 200%) of an estimated stimulated reservoir volume (SRV) of the unconventional formation in fluid communication with the primary wellbore. In certain embodiments, injecting step (b) comprises injecting a volume of the low particle size injection fluid equal to from greater than 100% to 250% (e.g., from greater than 100% to 200%) of the stimulated reservoir volume of the unconventional formation in fluid communication with the primary wellbore.

In some embodiments, the method can improve hydrocarbon recovery by improving the total hydrocarbon recovery from the primary wellbore and the secondary wellbores.

In some embodiments, injection of the low particle size injection fluid stimulates the unconventional subterranean formation. In some embodiments, the injection of the low particle size injection fluid allows for release of hydrocarbons from pores in a rock matrix. In some embodiments, the injection of the low particle size injection fluid improves the relative permeability of the region near the wellbore. In some embodiments, the relative permeability of the region near the wellbore is increased by at least 250 percent.

In these methods, the primary wellbore can be used for both injecting the LPS injection fluid and producing fluid from the unconventional subterranean formation. In some embodiments, injection of the LPS injection fluid can increase the production of hydrocarbons from the primary wellbore and secondary wellbore.

In some embodiments, the stimulation operation can further comprise preparing the LPS injection fluid. For example, in some embodiments, the stimulation operation can further comprise combining a single-phase liquid surfactant package described herein with an aqueous-based injection fluid to form a low particle size injection fluid.

In some embodiments when used in a stimulation operation, the low particle size injection fluid can have a total surfactant concentration of from 0.2% to 5% by weight, based on the total weight of the low particle size injection fluid.

In some embodiments, injecting a low particle size injection fluid described through a wellbore into the unconventional subterranean formation can comprise injecting the low particle size injection fluid through the wellbore and into the unconventional subterranean formation at a sufficient pressure and at a sufficient rate to stimulate hydrocarbon production from naturally occurring fractures in the unconventional subterranean formation.

The low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for varying periods of time depending on the nature of the rock matrix. The imbibing can occur during the injection step, between the injecting and producing step, or any combination thereof. In some examples, the low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for at least one day (e.g., at least two days, at least three days, at least four days, at least five days, at least six days, at least one week, at least two weeks, at least three weeks, at least one month, at least two months, at least three months, at least four months, or at least five months). In some examples, the low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for six months or less (e.g., five months or less, four months or less, three months or less, two months or less, one month or less, three weeks or less, two weeks or less, one week or less, six days or less, five days or less, four days or less, three days or less, or two days or less).

The low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for a period of time ranging from any of the minimum values described above to any of the maximum values described above. For example, the low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for from one day to six months. In one example, the wellbore can be a new wellbore; and the low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for from two weeks to one month. In another example, the wellbore can be a wellbore proximate to a previously fractured region of the unconventional subterranean formation; and the low particle size injection fluid can be allowed to imbibe into the rock matrix of the unconventional subterranean formation for from one day to two weeks.

In some embodiments, the wellbore used in the stimulation operation may have a substantially vertical portion only, or a substantially vertical portion and a substantially horizontal portion below the substantially vertical portion.

In some embodiments, the stimulation methods described herein can comprise stimulating a naturally fractured region of the unconventional subterranean formation proximate to a new wellbore (e.g., an infill well). In some embodiments, the stimulation methods described herein can comprise stimulating a naturally fractured region of the unconventional subterranean formation proximate to an existing wellbore.

In some embodiments, the stimulation methods described herein can comprise stimulating a previously fractured or previously refractured region of the unconventional subterranean formation proximate to a new wellbore (e.g., an infill well). In some embodiments, the stimulation methods described herein can comprise stimulating a previously fractured or previously refractured region of the unconventional subterranean formation proximate to an existing wellbore.

The previous fracturing operation may include hydraulic fracturing or fracturing with any other available equipment or methodology. The previous refracturing operation may include hydraulic fracturing or refracturing with any other available equipment or methodology. In some embodiments, after a formation that has fractures, such as naturally occurring factures, fractures from a fracture operation, fractures from a refracturing operation, or any combination thereof, the fractured formation may be stimulated.

In some embodiments, the stimulation operation can further comprise adding a tracer to the low particle size injection fluid prior to injecting the low particle size injection fluid through the wellbore into the unconventional subterranean formation; recovering the tracer from the fluid produced from the unconventional subterranean formation through the wellbore, fluid recovered from a different wellbore in fluid communication with the unconventional subterranean formation, or any combination thereof; and comparing the quantity of tracer recovered from the fluid produced to the quantity of tracer injected to the low particle size injection fluid.

Single-phase liquid surfactant packages (as well as the resulting LPS injection fluids) can be optimized for each unconventional reservoir and/or for the type of aqueous-based injection fluid. For example, a single-phase liquid surfactant package can be tested at a specific reservoir temperature and salinity, and with a specific aqueous-based injection fluid. Actual native reservoir fluids may also be used to test the compositions. In an embodiment, the single-phase liquid surfactant package is tested by determining the mean particle size distribution through dynamic light scattering. In specific embodiments, the mean particle size distribution of the aqueous-based injection fluid decreases after addition of the single-phase liquid surfactant package. In embodiments, the average diameter of particle size of the LPS injection fluid (aqueous-based injection fluid plus single-phase liquid surfactant package) is less than 0.1 micrometers. In an embodiment, when tested at the specific reservoir temperature and salinity, the average diameter of the LPS injection fluid is less than 0.1 micrometers. In specific embodiments, the average diameter in particle size distribution measurement of the LPS injection fluid is less than the average pore size of the unconventional reservoir rock matrix.

In some embodiments, the unconventional subterranean formation can have a temperature of at least 75° F. (e.g., at least 80° F., at least 85° F., at least 90° F., at least 95° F., at least 100° F., at least 105° F., at least 110° F., at least 115° F., at least 120° F., at least 125° F., at least 130° F., at least 135° F., at least 140° F., at least 145° F., at least 150° F., at least 155° F., at least 160° F., at least 165° F., at least 170° F., at least 175° F., at least 180° F., at least 190° F., at least 200° F., at least 205° F., at least 210° F., at least 215° F., at least 220° F., at least 225° F., at least 230° F., at least 235° F., at least 240° F., at least 245° F., at least 250° F., at least 255° F., at least 260° F., at least 265° F., at least 270° F., at least 275° F., at least 280° F., at least 285° F., at least 290° F., at least 295° F., at least 300° F., at least 305° F., at least 310° F., at least 315° F., at least 320° F., at least 325° F., at least 330° F., at least 335° F., at least 340° F., or at least 345° F.). In some embodiments, the unconventional subterranean formation can have a temperature of 350° F. or less (e.g., 345° F. or less, 340° F. or less, 335° F. or less, 330° F. or less, 325° F. or less, 320° F. or less, 315° F. or less, 310° F. or less, 305° F. or less, 300° F. or less, 295° F. or less, 290° F. or less, 285° F. or less, 280° F. or less, 275° F. or less, 270° F. or less, 265° F. or less, 260° F. or less, 255° F. or less, 250° F. or less, 245° F. or less, 240° F. or less, 235° F. or less, 230° F. or less, 225° F. or less, 220° F. or less, 215° F. or less, 210° F. or less, 205° F. or less, 200° F. or less, 195° F. or less, 190° F. or less, 185° F. or less, 180° F. or less, 175° F. or less, 170° F. or less, 165° F. or less, 160° F. or less, 155° F. or less, 150° F. or less, 145° F. or less, 140° F. or less, 135° F. or less, 130° F. or less, 125° F. or less, 120° F. or less, 115° F. or less, 110° F. or less, 105° F. or less, 100° F. or less, 95° F. or less, 90° F. or less, 85° F. or less, or 80° F. or less).

The unconventional subterranean formation can have a temperature ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the unconventional subterranean formation can have a temperature of from 75° F. to 350° F. (approximately 24° C. to 176° C.), from 150° F. to 250° F. (approximately 66° C. to 121° C.), from 110° F. to 350° F. (approximately 43° C. to 176° C.), from 110° F. to 150° F. (approximately 43° C. to 66° C.), from 150° F. to 200° F. (approximately 66° C. to 93° C.), from 200° F. to 250° F. (approximately 93° C. to 121° C.), from 250° F. to 300° F. (approximately 121° C. to 149° C.), from 300° F. to 350° F. (approximately 149° C. to 176° C.), from 110° F. to 240° F. (approximately 43° C. to 116° C.), or from 240° F. to 350° F. (approximately 116° C. to 176° C.).

In some embodiments, the salinity of unconventional subterranean formation can be at least 5,000 ppm TDS (e.g., at least 25,000 ppm TDS, at least 50,000 ppm TDS, at least 75,000 ppm TDS, at least 100,000 ppm TDS, at least 125,000 ppm TDS, at least 150,000 ppm TDS, at least 175,000 ppm TDS, at least 200,000 ppm TDS, at least 225,000 ppm TDS, at least 250,000 ppm TDS, or at least 275,000 ppm TDS). In some embodiments, the salinity of unconventional subterranean formation can be 300,000 ppm TDS or less (e.g., 275,000 ppm TDS or less, 250,000 ppm TDS or less, 225,000 ppm TDS or less, 200,000 ppm TDS or less, 175,000 ppm TDS or less, 150,000 ppm TDS or less, 125,000 ppm TDS or less, 100,000 ppm TDS or less, 75,000 ppm TDS or less, 50,000 ppm TDS or less, or 25,000 ppm TDS or less).

The salinity of unconventional subterranean formation can range from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the salinity of unconventional subterranean formation can be from 5,000 ppm TDS to 300,000 ppm TDS (e.g., from 100,000 ppm to 300,000 ppm TDS).

In some embodiments, the unconventional subterranean formation can be oil-wet. In some embodiments, the unconventional subterranean formation can be water-wet. In some embodiments, the unconventional subterranean formation can be mixed-wet.

In some embodiments, the LPS injection fluid can be injected at a wellhead pressure of at least 0 PSI (e.g., at least 1,000 PSI, at least 2,000 PSI, at least 3,000 PSI, at least 4,000 PSI, at least 4,500 PSI, at least 5,000 PSI, at least 6,000 PSI, at least 7,000 PSI, at least 8,000 PSI, at least 9,000 PSI, or at least 10,000 PSI). In some embodiments, the LPS injection fluid can be injected at a wellhead pressure of 10,000 PSI or less (9,000 PSI or less, 8,000 PSI or less, 7,000 PSI or less, 6,000 PSI or less, 5,000 PSI or less, 4,500 PSI or less, 4,000 PSI or less, 3,000 PSI or less, 2,000 PSI or less, or 1,000 PSI or less).

The LPS injection fluid can be injected at a wellhead pressure ranging from any of the minimum values described above to any of the maximum values described above. For example, in some embodiments, the LPS injection fluid can be injected at a wellhead pressure of from 0 PSI to 10,000 PSI (e.g., from 0 PSI to 4,500 PSI, or from 2,000 PSI to 6,000 PSI). In some embodiments, the LPS fluid can be used in a reservoir stimulation operation, and the LPS injection fluid can be injected at a wellhead pressure of from 0 PSI to 1,000 PSI.

In some embodiments, the method further comprises identifying one or more secondary wellbores that are in fluid communication with the primary wellbore. The one or more secondary wellbores that are in fluid communication with the primary wellbore can be identified and selected for use in the methods described herein by, for example, performing a tracer study to identify one or more secondary wellbores in fluid communication with the primary wellbore. In some embodiments, the one or more secondary wellbores that are in fluid communication with the primary wellbore can be identified and/or selected by a method that comprises (i) injecting a tracer into a primary wellbore in fluid communication with the unconventional formation; (ii) measuring a tracer response in a plurality of wellbores in geographic proximity to the primary wellbore; and (iii) using the tracer response to identify the one or more secondary wellbores in fluid communication with the primary wellbore. The tracer response can comprise tracer mass recovery, rate of tracer recovery, and/or tracer concentration profile in the plurality of wellbores in geographic proximity to the primary wellbore. In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises analysis of fracture driven interactions between wellbores present in fluid communication with the unconventional subterranean formation. In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises a pressure transient analysis (e.g., by observing which wellbores exhibit a change in wellhead and/or bottom-hole pressure in response to changes in pressure at the primary wellbore). In some embodiments, identifying and/or selecting the one or more secondary wellbores in fluid communication with the primary wellbore comprises analysis of geological features of the unconventional subterranean formation, such as naturally occurring faults or fractures.

EXAMPLES

The invention will be described in greater detail by way of specific examples. The following examples are offered for illustrative purposes, and are not intended to limit the invention in any manner. Those of skill in the art will readily recognize a variety of non-critical parameters which can be changed or modified to yield essentially the same results.

The compositions and methods described herein can relate to the compositions described in U.S. Pat. No. 10,197,489 to McCarty et al.; U.S. Pat. No. 11,753,582 to Walker et al.; U.S. Pat. No. 11,760,921 to Walker et al.; U.S. Pat. No. 11,834,609 to Walker et al.; and Alvarez, J. O. et al. “Design of Chemical EOR in Unconventional Reservoirs” Proceedings of the Unconventional Resources Technology Conference (URTeC): 3870505, Denver, Colorado, USA, 13-15 Jun. 2023 (DOI: 10.15530/urtec-2023-3870505), each of which is hereby incorporated by reference in its entirety.

Example 1: Design of Chemical EOR in Unconventional Reservoirs

Unconventional development of oil and gas shale and tight reservoirs has globally become very active over the past ten years from advances in hydraulic fracturing operations. Due to the tightness of the shale rock formations (generally much less than 1-md and often measured in nano-darcy), hydraulic fracturing enables enhanced production by providing more contact with the reservoir and allowing ease of fluid production into the wellbore. However, unconventional reservoirs petrophysical characteristics of low porosity, ultralow permeability, marked heterogeneity and high total organic content (TOC) lead to current recovery factors that often do not exceed more than 10% of the original oil in place (OOIP) with average values of 5 to 6% (Alharthy et al., 2017; Barba, 2015). This example proposes the use of surfactant additives in stimulation fluids to re-energize producing wells and increase recovery factors.

To improve oil recovery on unconventional horizontal wells, it is desirable to optimize the physical and chemical properties of the stimulation fluid. The stimulation fluid should be compatible with the reservoir rock and fluids, be easily removed from the formation, present low fluid flow friction pressures, be easily made under field conditions, and be relatively inexpensive. Hence, there is a need for water-based stimulation fluids to boost production of unconventional wells mid-life. This need is evident from the production profile of unconventional wells where initial oil production rate declines rapidly and stabilizes at a relatively low rate, which is maintained for many years. This decline is partly natural due to low delivery of the reservoir and fracture closure but partly due to flow dynamics in fractures, wettability of stimulated reservoir volume (SRV), matrix and micro-fractures, blockage of fracture face and proppant by precipitation or trapped fluids, sand blockage, among others. Herein, a study was conducted which presents a stimulating method to boost production of existing wells by cleaning up fracture and proppant in-situ, alter wettability of SRV matrix and micro-fractures, lower interfacial tension (IFT) to mobilize trapped fluids, and re-pressurize the fracture system restoring their conductivity.

This example used a comprehensive workflow (FIG. 1) where a closed feedback loop was implemented between labs, pilot teams, and field operations to develop this technology (McCarty et al., 2019). The workflow helped address several key questions such as the types of principles to be used in designing the surfactant solution, the ways to monitor the flow of stimulation fluid and determine its performance and the ranges of stimulation volume and the type of response to be expected. A brief description of the selected approach is given below, and more details can be found in the next section.

Surfactant evaluation for improved oil recovery in tight unconventional rocks at lab scale (Xu & Fu, 2012; Wang et al., 2012; He et al., 2015; Li et al., 2016; Alvarez & Schechter, 2017; Yarveicy et al., 2018; Alvarez et al., 2018; Tran et al., 2020; Wei et al., 2023) and field trials (Shuler et al., 2016; Mohanty et al., 2017; Bidhendi et al., 2019; Pospisil et al., 2022) revealed the importance of wettability alteration, IFT reduction, osmosis uptake, leak-off reduction, soaking time, and aqueous stability (or lack thereof).

Shuler et al., (2016) stimulated a carbonate reservoir vertical well oilfield using a huff-n-puff scheme. The authors claimed that surfactant treatments reduced production decline and increased oil recovery by close to 18 Mbbls. Mohanty et al (2017) performed preloading field trials to mitigate fracture driven interactions (FDIs). They injected 3 to 20 Mbbls of liquid plus a chemical blend recovering 12 Mbbls of oil after 8 months of flowback and 5 weeks of soaking. (Bidhendi et al., 2019) executed a huff-n-puff surfactant trial, but no production results were reported. Lastly, Pospisil et al (2022) performed a single huff-n-puff well. These schemes included injection of gas and surfactants in shorth cycles by a proprietary delivery mechanism. The authors reported an oil rate increase from 55 bpd to 68 bpd on a 30-day average, and that by DCA, the pad would recover a total close to 7 Mbbls of oil including the impacts of shut-in for injection. All these studies showed surfactant potential to increase production after stimulation, but they do not provide a comprehensive workflow for pilot design and a robust surveillance analysis and optimization (SA&O) plan and execution that confirms proposed recovery mechanisms and assesses potential changing reservoirs properties and with that increase in production.

Nevertheless, a common observation in all these efforts is the crucial role of the wettability of SRV matrix and micro-fractures, where co-current imbibition results suggest a mixed-to-oil wet behavior (Yousefi et al., 2020; Alvarez et al., 2018). Thus, the example formulated a wettability-altering surfactant mixture to improve brine imbibition and unlock trapped oil. Additionally, the surfactant formulation was designed to be able to clean up the fracture face, remove precipitations from the proppant pack, and release trapped oil. This clean-up stimulation is an overlooked aspect in mid-to-late life of horizontal wells where prolonged exposure to reservoir fluids can lead to clogging of fracture face and proppant pack (which behaves as a compacted sandpack), restricting oil flow into the fractures and subsequently into the wellbore.

Once the design of surfactant package was finalized, the efforts shifted to developing an SA&O method to confirm surfactant performance in-situ using chemical tracers, productivity index (PI), rate transient analysis (RTA), and decline curve analysis (DCA), among others. Chemical and proppant tracers have been used for a wide range of SA&O objectives in unconventional wells. These objectives include monitoring the flowback of fracturing fluid and impact of various additives on clean-up and flowback efficiency (Asadi et al., 2002; Woodroff et al., 2003), well inflow profiling and stage-level response to operational changes (Panichelli et al., 2017), proppant placement (Raterman et al., 2018; Wood et al., 2018) and monitoring interwell & inter-bench connectivity over time (Kumar et al., 2018; Salman et al., 2014; Wood et al., 2018). Here the study use chemical tracers to quantify stimulation water recovery, measure communication to offset producers, monitor surfactant transport in hydraulic fracture network, and quantify the impact of surfactant imbibition by comparing the tracer response between both pilot wells.

The next phase of the technology development was estimating the stimulated volume and forecasting the production response. To this end, numerical simulations were employed. Due to the uncertainties of modeling unconventional reservoirs (fracture volume/geometry, orientation/density of natural fractures, interwell connectivity, etc.), a simpler conceptual model approach was employed. Due to these uncertainties, a simpler conceptual model is preferred over a conventional detailed reservoir level static model. Conceptual models can be as simplistic as a quarter of a fracture model which assumes symmetry and homogeneity not just within a fracture but throughout the well/formation intersection. Such models were used by Hoffman & Reichhardt (2020) to study recovery mechanisms of cyclic gas injection in unconventional reservoirs and by Kanfar & Clarkson (2017) to study Huff-n-Puff injection in unconventional wells. Other researchers have used uniform and equally spaced fracture model to represent a fractured shale and tight wells (Xiong et al., 2021; Sierra et al., 2013). While quarter fracture or equal-spaced fracture models are easier to construct they tend to struggle in reproducing field observations because they rely on the existence of linear flow. Acuña (2018, 2020) proposed a method to create simple reservoir models that reproduce the hydraulic behavior of complex networks of fractures. To this end, fractal dimension and RTA are used to create bi-wing or “butterfly” models that hydraulically represent the complex geometry of multi-stage fractures and capture the deviation from linear flow. Using such fractal swarm models is supported by core samples results by Raterman et al. (2018) that show that hydraulic fractures occur in swarms and are not uniformly placed. In this example, fracture swarm models were used to create the subsurface fracture network for the wells. Enhanced recovery mechanisms such as wettability alteration and IFT reduction were modelled using a commercial software.

This example aims to close the current gaps in the literature by describing and executing a detailed workflow and SA&O to pilot a surfactant stimulation technology in unconventional horizontal wells. Moreover, it highlights different aspects of technology development and describes the pilot trials of using water and surfactants as a stimulation fluid on existing wells from an unconventional asset. First, computer-based modeling is used to predict pre-test and calibrate post-test well performance, addressing key physical mechanisms potentially impacting the recovery. Then, a correlated set of experiments are performed to optimize chemical formula and concentrations, addressing phase behavior for fluid stability, contact angle change for wettability alteration, IFT reduction and core flood testing for imbibition. Finally, field test execution and implementation of the SA&O plan are discussed, advocating integration of tracer, production, pressure, and productivity index data, to assess chemical EOR potential and well performance effects for two pilot wells. The results showed that the use of surfactants could improve oil recovery by wettability alteration and IFT reduction, maximizing well performance after stimulation.

Methodology

This technology development focuses on designing a chemical stimulation for unconventional reservoir wells to maximize hydrocarbon recovery and extend the life of the fields leveraging chemical EOR technology. This stimulation fluid maintains clean fractures and penetrates deeper into the stimulated area, mobilizing more hydrocarbons, by altering rock wettability and lowering interfacial tension. These objectives are achieved by performing computer-based modeling to address key physical mechanisms and assess potential estimated ultimate recovery (EUR) uplift and recovery ranges. Then, field trials are performed with robust SA&O plan validating critical pilot signposts. Thus, this section describes a workflow to evaluate and compare the efficiency of surfactants, as a stimulation additive, in recovering hydrocarbons from unconventional wells.

Reservoir Modeling: Modeling work includes improvement of the history match of production data from the two pilot wells (Reference and Surfactant wells) before predicting performance of pilot tests with surfactant effects. For this example, the Reference well is a well that was stimulated with water only and the Surfactant well was stimulated with water plus surfactant additives. More details are given in the next sections. The same model was also used to predict performance by injecting surfactant added fluids staying below fracturing pressure. The concept of applying surfactants into existing horizontal wells is also examined from the use of modeling.

Unconventional reservoirs may be represented as dual permeability and dual porosity system. They are composed of a very tight (low permeability) matrix, that stores most of the hydrocarbon and an extensive network of hydraulic and natural fracture that creates the flow channels that carry the fluids from matrix to the well bore (FIG. 2). A two-dimensional representation of a well-bore in unconventional reservoirs is shown in FIG. 2. It has a dense network of relatively short natural fractures that are intersected with long hydraulic fractures. Solving a system like this numerically using a reservoir simulator becomes very computationally intensive. Only few researchers have attempted such models at large scale (Yu et al., 2021). Most researchers chose a simplified representation such as a quarter-fracture model or an equally spaced planar fracture model. Recently, Acuña (2020) proposed a more elegant yet simple model called the Fracture Swarm model. A fracture swarm model is a simplified representation of a complex fracture network, which honors the non-linear flow with fractal network and easy to history match as it is developed from rate transient analysis of the production data from a well under study. An example of a fracture swarm model is shown in FIG. 2. This model is computationally much less intensive, which is useful for EOR type simulation study.

The workflow used to generate the fracture swarm model is shown in FIG. 3. First, rate transient analysis is conducted on the primary production data of the well under study. Oil, water and gas rate and bottom hole pressure data are the input of the RTA model. A special Fractional Dimension—RTA model (Acuña, 2017, 2018) is used to interpret the total fracture half-length (X_mf) and fractal dimension (δ) for the system. The total fracture half-length is indicative of the total matrix fracture interface area available to the flow and the fractional dimension is an indicator for the flow regime in the reservoir. For most unconventional wells, this number is less than 0.5, suggesting that the flow is sub-linear. This output can then be converted into a fracture swarm model using an in-house tool. Fracture swarm models generated from RTA on production data of a usual 2-mile long lateral well can produce about ˜700 to 900 individual fractures. Simulating hundreds of fractures (fine grids) can again be computationally prohibitive, therefore, only a fifth of the well bore was modelled. For simulation purposes, the fracture swarm network was imported as EDFM grid embedded in a regular simulation grid that represents the tight matrix. Straight-line relative permeabilities were used for fractures cells.

As the fracture network used in the simulations model is generated by using well production data, the resulting simulation output is well history matched from the beginning and may require only small tweaks. Once the model produced volumes are sufficiently aligned with the well under study, the simulation model can be used to design and optimize a stimulation slug for fracture stimulation. The history match obtained is shown in FIGS. 4A-4B. It is worth noting that the production rates are also scaled to ⅕ of the actual well rates. A quick history match turnaround time for this model makes this workflow scalable and can be applied to any well by following a simple workflow.

Laboratory Tests and Surfactant Selection: Laboratory tests were performed to optimize chemical formulation and concentrations. Liquid rich shale cores and crude oil were used. Surfactants were synthetized in-house and carefully selected to fully function at reservoir temperature and salinities. The lab testing workflow included:

• • 1) Surfactant phase behavior for fluid stability and emulsion tendency.
  • 2) Contact angle measurements for initial wettability as well as wettability alteration. Contact angle experiments were performed using the captive bubble method at reservoir temperatures.
  • 3) IFT measurements to confirm IFT reduction. IFT measurements were performed using the pendant drop and spinning drop methods.
  • 4) Coreflood testing for surfactant spontaneous imbibition and oil recovery potential. Formulations were screened against the brine baseline imbibition.

Field Testing Design and Execution: Results obtained from laboratory tests, such as optimized concentrations, and reservoir modeling work, addressing potential technology, were used as the basis for the recommendation for field test pilots. The recommendations suggested the use of surfactant additives with brackish water at concentrations of 0.10% to 0.2% for field tests on producing wells as stimulation technique.

Two similar 2-miles horizontal wells, on adjacent pads, were selected for the pilot. These wells were completed with identical designs and put on production at similar times. After few weeks of production, electrical submersible pumps (ESP) were installed in both wells as their artificial lift method to maximize production. The pilot was executed approximately two years after the wells were put on production when decline factors were reduced and wells were producing 100 to 200 bpd. One of the pilot requirements was to have clear well pre-injection trends baseline and production profiles to fully assess stimulation impact over time and determine enhanced ultimate recovery (EUR). This was clearly achieved by both well pilot candidates.

To address recovery mechanisms and identify the effect of surfactants, the pilot was divided into two trials performed in similar timeframes, under similar conditions, and controlled injection parameters. The first trial was the Reference Well and the stimulation fluid included brackish water (approximately 10,000 mg/L TDS) and 0.1 to 0.25 gpt of biocide. The second trial was the Surfactant Well, and the stimulation fluid contained by brackish water (around 10,000 mg/L TDS), 0.1 to 0.25 gpt of biocide and 0.1% to 0.2% of surfactant.

The field set up schematic is shown in FIG. 5, the system consisted of a water source that was pumped and stored in tanks. From there, water was mixed with the surfactant (only for the Surfactant Well) and biocide as well as non-reactive tracers for pilot surveillance. This fluid mixture was bullheaded into the wells by pressure pumps.

The job site was managed by personnel overseeing partner contractors. The contractors consisted of a pulling unit crew, well-head prep crew, pressure pump truck crew, chemical additive crew, and water transfer crew. The equipment required for the job consisted of a data van, pump trucks (associated equipment), 500 bbls working tanks (lay-flat lines and water transfer pumps), chemical additive pumping/metering trailer, and ISO tanks with cradles/trailers.

To stimulate both wells, the ESPs were removed, the tubing was pulled, and the injection was performed through the completion casing. A frac valve was installed and iron was connected to the wellhead from the pressure pumping truck. The working tanks were filled and treated with biocide. The tanks were plumbed in sets and alternated feed during execution. One set would feed the pump while the other set was back filling with water. The water was gravity fed to two tri-plex pumps each mounted on a pressure pumping truck. The pumps were capable of 12 bpm pump rate each. The ISO containers with the surfactant fed the intake side of the chemical addition trailer pump. The discharge side of the chemical addition trailer pump fed surfactant into the discharge side of the acid pump truck's pump. This is where the surfactant and water streams combined prior to the wellhead to travel down hole. The pump trucks alternated pumping to allow for maintenance.

The Reference and Surfactant wells were stimulated with 30 to 60 Mbbls of water plus additives. Both wells took the same amount of fluid to ensure similar injection parameters. Injection rates ranged from 6 to 12 bpm and the complete operation lasted from 2 to 4 days. The job was pumped continuously until the total predetermined volume was pumped away. After the wells were stimulated, a period of 10 to 25 days of soak time was observed. Then, electrical submersible pumps were reinstalled, and wells were put back on production.

Surveillance Analysis and Optimization (SA&O) Matrix: The primary purpose of the surveillance analysis and optimization (SA&O) matrix is to reduce uncertainties from field measurements and better assess pilot objectives and recovery impact. During the execution, the main objective was to ensure the correct volumes and concentrations of surfactant, tracer and other chemicals were injected. The workflow proposed is meant to collect pilot data to identify early signposts and perform analysis to support the conceptual model with the objectives of:

• • 1) Safely execute the stimulations of the Reference and Surfactant wells.
  • 2) Assess pilot results and confirm proof of concept (POC).
  • 3) Generate clear signposts to compare baseline production by SA&O.
  • 4) Estimate EUR uplift and possible reserves impacts.

A robust SA&O plan, with clear signposts, was developed to facilitate pilot interpretation and future optimization. FIG. 6 shows the SA&O Matrix used for the pilot. This matrix shows the SA&O activities to execute before, during and after the pilot as well as the desired type of measurement needed to confirm conceptual models. Notice that the measurements column also has the expected time the response for the specific SA&O activity should have (enough data) to be conclusive and assess performance. This distinction is very important when evaluating pilots due to the changing nature of the flowback activities. Signposts with signals strengths are also noted on the matrix showing positives and negatives responses for each surveillance activity proposed.

Production Rates and Bottom Hole Pressures: Pre- and post-injection daily production rates (oil, gas, and water) and bottom hole pressures for the Reference and Surfactant wells and the offset wells were used for interpreting well performance. Pilot and offset wells were constantly tested to ensure high quality field data. The information collected from the field was not only used to assess oil, gas, and water recoveries after stimulation to compare to pre-injection trends, but also to calculate productivity index (PI) to evaluate the reservoir response after stimulation and determine possible reserves incremental. Productivity Index (Eq. 1) relates well liquid flow rate (Q!) to the change in bottomhole flowing pressures (P) with respect to the reservoirs initial pressure (Pi) (Economides, 2013). This signpost is assessing the ability of a chemically stimulated reservoir (surfactant well) to deliver fluids to the wellbore and how it can be compared to a reservoir stimulated by only water (Reference well).

PI = Q L Pi - P

Decline Curve Analysis: For the Decline Curve Analysis (DCA) in these unconventional wells, the Modified Arps decline curve method, on in-house and commercial DCA software, was used. The initial portion of the data was fitted using a hyperbolic curve, with the b-factors between 0.9 and 1.1. The terminal decline rate (D_min) was set between 5-15% after well production reached the predetermined value.

DCA methods were applied to both the Reference and Surfactant wells before and after the pilot took place. Before injection, wells have several months of production, so the historical data was declined in the same flow regime as anticipated in the long-term forecast creating a well robust DCA. Post-injection DCA was performed after 12 months of pilot production, improving the analysis confidence due to multiple field data. The DCA SA&O signpost considered the rate of decline as well as the pre- and post-stimulation EUR to determine technology performance.

Rate Transient Analysis: For the Rate Transient Analysis (RTA), the Fracture Swarm Fractal Networks (Acuña, 2020) was used on a commercial software. This RTA method is based on the observation that the variation of reservoir volume with distance from the fractures is what determines well behavior. Conventional RTA assumes equally spaced fractures, whereas this methodology analyzes fracture systems with variable geometries irrespective of fracture complexity. Moreover, the characteristic flow volume (CFV), as the reservoir volume variation with distance from the fractures, determines a well's hydraulic behavior. CFV is calculated from well rate data and the RTA analysis provides an estimation of the product total fracture half-length (X_mf) and matrix permeability (k) elevated to a flow dimension parameter (δ) as X_mfk^δ. That is the general form of the term X_mf√{square root over (k)} obtained with classic RTA if fractures are equally spaced (δ=0.5). For the propose of this example, the variable X_mf is called Effective Fracture Length (EFL).

RTA was applied to both Reference and Surfactant wells to address changes in EFL before and after stimulation as signpost for changes in fractured area due to fracture-face cleanup and rock-fluid and fluid-fluid interactions.

Tracers: Tracers were deployed in both Reference and Surfactant wells. Global material balance water (MBW) tracers were used in this pilot. Chemical tracers (naphthalene sulfonates—NDSA) were used to quantify stimulation water recovery, measure communication in offset producers and quantify the surfactant imbibition performance on the oil recovery by comparing the tracer response between both pilot wells. Tracer sampling in offset wells was done daily for 2 to 3 weeks to detect any breakthrough and measure tracer peak concentration. Subsequently, sampling frequency reduced to 1 to 3 samples per week and sampling continued up to 8 months. Tracer response from the Reference and Surfactant wells was compared in terms of mass recovery and the rate at which the tracer flows back to establish the effectiveness of chemical. The tracer concentration profile can also be compared against the surfactant and the salinity measurements from the produced water. Tracers were used to estimate chemical penetration into the fracture system and the size of the enhanced permeability region (EPR). Their signposts included flowback concentrations as indications of surfactant penetration and/or imbibition into the fracture face.

Surfactant: A surfactant blend was used on the Surfactant well to reduce formation damage and improve oil recovery. Surfactant flowback concentration was determined by High-performance liquid chromatography (HPLC) measurements to assess chemical retention on the fracture face as indication of wettability alteration and fracture cleaning. Early and fast flowback would indicate limited wettability alteration whereas slow and delayed flowback would be a signpost of an effective wettability alternation taking place after stimulation. At the end, surfactant flow back would help understand performance and determine future trials injection strategy and design optimization.

Salinity: Reservoir brine salinity was determined before well stimulation in both the Reference and Surfactant wells. Also, the brackish water salinity used for the pilot was assessed. This part of the SA&O addresses the level of mixing of brackish water and reservoir brine at flowback. Values of flowback water salinity close to injection salinity would be an indication of a limited mixing and formation penetration. On the other hand, having a significantly higher than injection salinity water flowback would be signpost of effective fluid penetration into fracture system.

Results and Discussions

The results and observations from the proposed workflow, SA&O, and field testing of stimulation fluids to enhance hydrocarbon recovery are discussed in this section. Reservoir modeling, surveillance analysis and optimization with early signposts of key data and analysis to support the conceptual model as well as analytical methods such as RTA/DCA and tracer response, are combined to provide an integrated interpretation of pilot observations. In addition, results are discussed to show consistency in the pilot workflow and SA&O proposed.

Modeling Results and Key Physical Mechanisms Impacting Recovery: Three possible enhanced oil recovery mechanisms may be involved in the surfactant stimulation of an unconventional well, namely wettability alteration, IFT reduction and fracture-face cleanup. Surfactants can alter the wettability of the reservoir rock to more water-wet. A water-wet rock will make flow of oil easier and hence result in increased oil production. Surfactants also tend to reduce the oil-water interfacial tension, lower IFT can help unleash the oil droplets trapped in small pores and hence open more pathways for oil to flow. Lastly, fracture face cleanup can be considered an independent mechanism or any combination of all the above mechanisms acting on the fracture matrix-interface.

In addition to altering wettability and unleashing capillary trapped oil, surfactants can also solubilize organic debris that could have plugged the fracture-matrix interface and hence enhance the flow of oil from the matrix to fracture. Fracture face cleanup or wettability alteration at the interface can be modeled as matrix-fracture transmissibility improvement. An in-house modeling design was developed and implemented in INTERSECT simulator, which can enhance the matrix-fracture transmissibility as a function of surfactant concentration. FIG. 7 shows the field results of a treated well and the post stimulation matrix-fracture transmissibility is about 10 times higher than the initial transmissibility. For predictive forecasting and estimation, several surfactant field trails will have to be simulated to develop a strong correlation between chemical slug design parameters and the expected increment in PI or transmissibility.

Surveillance Analysis and Optimization (SA&O) Results: A comprehensive SA&O matrix was designed to address key mechanisms associated with surfactants test in existing wells. These details are important as they directly drive the cost, the schedule, and the learning plan for the pilot. The following recaptures the pilot objectives and provides additional details developed:

• • 1) Testing the potential improved production and recovery from optimized surfactants in existing unconventional wells.
  • 2) Assessing the potential driving mechanisms for improved performance as observed in the laboratory tests, simulation, and theoretical basis: imbibition due to wettability changes, fracture cleanup, reduced interfacial tension, and fluid stability.

Production Rates and Productivity Index Results: Well tests and allocated productions were used to evaluate Reference and Surfactant wells performance. Both wells were stimulated with approximately 50 Mbbls of water. The Reference well was only treated with water and biocides whereas the Surfactant well used a surfactant concentration of 3.2 gpt. After stimulation, pilot wells were put back on identical drawdown management to keep testing variables to the minimum. The main variables to observe in this part of the SA&O were initial oil recoveries or production peaks and production declines after putting the wells back on production following its stimulation as indication on changes in the reservoir due to rock-fluids and fluid-fluid interactions. Higher initial recoveries are indications of IFT reductions between oil and water and slower declines are signpost of surface property changes like wettability alteration and fracture cleanups.

In this pilot, the Reference well is intended to serve as a comparison to separate the potential benefits of injecting a fluid into a horizontal unconventional well, and with this increasing its bottom hole pressure due to hydrostatic forces. Injecting water into the Reference well may temporarily re-energize the well by increasing its wellbore pressure, but this effect is expected to be very temporary unless another agent, such as surfactants, are added that can alter rock and fluid properties appending chemical energy. FIG. 8 shows production rates before and after injection for the Reference well and its pre-injection oil decline curve. At the time of stimulation, the Reference well was producing around 150 bpd. Adding the ESP pull, injection, soaking time, and ESP reinstall, the well was shut in for about 20 days.

After putting the wells back on production, the Reference well exhibited very high initial water rates. This was expected and well managed by its ESP. Most importantly, initial oil rates were three times higher than pre-injection times confirming that adding hydraulic energy to these depleted reservoirs can have a temporary impact on oil production. However, this effect lasted fewer than 70 days where pre-injection oil rates were achieved again. After high initial liquids production (water and oil), gas rates also temporarily increased. An initial gas suppression effect was observed due to the rearrangement of the fluids in the fracture space cause by pressure increases. However, gas-oil ratio (GOR) had little change after water injection, indicating that permeability to gas was not altered significantly. This was expected as no chemical agents were used in this well that can alter wettability and reduce IFT, affecting relative permeability behaviors. Lastly, the oil rate decline showed by the Reference well was very fast indicating that reservoir and fracture properties did not permanently change after stimulation, and the oil recovered is mostly part of flushed production after adding hydraulic pressure to the reservoir by the water injection.

Cumulative oil production was accounted for including production lost during injection, soaking and flowback operations. FIG. 9 shows the oil cumulative production for the Reference well. After 365 days, the Reference well added an increased oil production of 7,600 bls, mostly attributed to initial flushed production after stimulation.

The Surfactant well rates and declines were also recorded and are shown in FIG. 10. At the time of stimulation, the Surfactant well was producing around 180 bpd. Adding the ESP pull, injection, soaking time, and ESP reinstall, plus some peripheral field operations, the well was shut in for about 40 days.

In a similar fashion to the Reference well, the Surfactant well flowback after stimulation showed very high initial water rates. The ESP installed on the well was able to move injected fluid and enable oil to be produced right after few days of de-watering. Initial oil rates were more than three times higher than pre-injection trends. The initial oil rate response for the Surfactant well was better than the Reference well, but not drastically different. This proves that there was a well response to the additional energy added by injecting fluids into a depleted unconventional well. However, the main difference between the Reference and Surfactant well is the longer lasting oil production of the Surfactant well above its pre-injection decline curve. After a year of production post-stimulation, the Surfactant well was producing higher oil rates than pre-injection predictions corroborating the impact of the chemical energy provided by the surfactant additives. IFT reductions between oil and water improved instantaneous and continuous oil flowback. Additionally, reservoir wettability alterations and fracture cleanup with time changed reservoir properties reducing oil declines and preserving improved recoveries for more than 365 days. In contrast, the Reference well only maintained oil production after stimulation above pre-trend for about 70 days.

In the Surfactant well, both the oil and gas production increased after stimulation, indicating changes in relative permeabilities and possible fracture cleanings favoring fluid flow in the fracture space. These changes in hydrocarbon rates are attributed to the surfactant properties of altering wettability and reducing IFT affecting capillary and viscous forces. Finally, the Surfactant well showed a slow decline after injection, much slower than the Reference well, indicating changes on the reservoir properties and not only a flushed production due to fluid injection and shut in.

The Surfactant well cumulative production is shown in FIG. 11, and is compared to the cumulative production using the pre-trend decline curve. After subtracting all the lost production due to injection, soaking and flowback periods, the Surfactant well increased its production by 31,720 bbls after 365 days of post-injection operation due to the chemical stimulation. It is important to note that the Surfactant well has not yet reached initial pre-injection trend production by the time of this publication, so the well is still improving recovery.

Another key piece of the SA&O collected in this pilot was bottom hole pressures (bhp) before and after stimulation for the Reference and Surfactant wells. These bottom hole pressures were used to calculate wells productivity index (PI) to evaluate the reservoir response after stimulation and determine possible reserves incremental due to a change on reservoirs properties. The use of PI (Eq. 1) is required to normalize rates with pressures, reducing variations caused by field operations, and to have an assessment of the reservoir deliverability. Since both Reference and Surfactant wells were completed and put on production on similar times and due to their closeness (contingent pads), both wells' PIs can be compared in one graph as shown in FIG. 12. Even though the Reference and Surfactant wells had slightly different drawdowns at their beginning of their lives, well before stimulation (more than 200 days before) they exhibited very similar PIs consistent with the fact that the wells were completed with identical designs, proximity from each other and put on production at similar times and then lifted with identical ESPs. However, after stimulation, both wells behaved very different.

The Reference well shows a clear increase on PI after being stimulated with only water, but its productivity decreases to pre-injection values almost immediately after less than 20 days of being putting back on production. This behavior is representative of a system that suddenly increased pressures due to viscous forces (water injection) and shut-in time, but immediately decreased after the well is opened to production. Hence, flushed production and rapid pressure decline marked the rapid falling tendency of the Reference well PI. After this fast decline, Reference well PI came back to pre-injection values maintaining that trend for more than 350 days. In short, the Reference well did not experience any changes on the reservoir that could maintain higher levels of PI in time after stimulation and only showed a rapid declining PI.

Conversely, the Surfactant well not only showed a clear PI increase after being put back on production, but also had a more sustained PI trend relative to the pre-injection values. In fact, the Surfactant well PI comes back close to pre-stimulation ranges after more than 250 days of production and maintaining higher PI values than the Reference well after stimulation. The prolonged change in PI and its slower decline is an indication of reservoir propriety changes caused by the surfactant additives.

Fracture cleanup and wettability changes on the fracture surface facilitating hydrocarbon recovery and IFT reductions improving fluid movement to the wellbore increased recovery at similar drawdown strategies. In summary, the surfactant well showed higher PI and slower decline than the Reference well (with water injection only). It is noticeable for these two cases that time duration considered for proper assessment is important due to the tight nature of the rocks, potentially requiring clear observations for rock-fluid interaction impacts.

Decline Curve Analysis and EUR Estimations: Decline curve analysis was used in the Reference and Surfactant wells to determine estimated ultimate recovery (EUR) changes after stimulation (FIGS. 13A-13B), and with that evaluate surfactant stimulation potential in producing unconventional horizontal wells. Pre-injection DCA was performed considering several months of production and the post-injection DCA was performed after 12 months of post-pilot production. FIG. 13A shows the DCA for the Reference well. The analysis concluded that injecting approximately 50 Mbbls of water in the Reference wells increased its oil EUR by 2.3% with no change in gas EUR.

DCA was also performed to the Surfactant well and if is shown in FIG. 13B. It showed that the Surfactant well increased its EUR after stimulation by 7.8% for oil and 18.5% for gas. Based on this SA&O signpost, it can be concluded that the Surfactant well shows a larger incremental EUR uplift than the Reference well (with water injection only).

Rate Transient Analysis Results: Rate Transient Analysis was used to analyze well response using only liquid phases and matching performance before and after injection. RTA was applied to both Reference and Surfactant wells to address variations in effective fracture length (EFL) before and after stimulation as signpost for changes in the stimulated area due water and surfactant injection. Production and pressure history was matched up to the injection. Then, the post-injection trend was matched by modifying the effective fracture length. This step made possible calculation of fracture area and other parameters.

FIG. 14A-14B shows the matched RTA before (FIG. 14A) and after (FIG. 14B) injection for the Reference well. The Fracture Swarm Fractal Networks (Acuña, 2020) was used on a commercial software. The RTA analysis provides an estimation of the product total fracture half-length (X_mf) that was called effective fracture length (EFL) in this study. The calculated pre-injection effective fracture length was 96,000 ft, and after stimulation, with approximately 50 Mbbls of water, the new RTA showed an effective fracture length of 103,000 ft. This change in EFL is attributed to the viscous forces given by the water injection that may have temporarily reopened closed microfractures in the enhanced permeability volume.

However, based on pressure data and RTA studies, well pressure after stimulation with only water followed similar trends as pre-injection. This signpost indicates that minimum changes happened on the reservoir and the impact, and changes in EFL, briefly lasted during post flushed production.

FIG. 15A-15B shows the RTA for the Surfactant well before (FIG. 15A) and after (FIG. 15B) stimulation. Pre-injection EFL are very similar to the Reference well, but post-injection EFL differed notably. Pressure trends after injection showed a longer lasting effect on the reservoir, consistent with the increased production discussed in previous sections of this example. To match after surfactant stimulation production and pressures, the effective fracture length had to be increased by 41%. This behavior suggests that surfactant rock-fluid and fluid-fluid interactions made a difference compared with the only water treatment and changed reservoir and fracture properties. Positive changes in EFL after stimulation are the expected signposts when surfactant fluids modify rock surface wettability, cleanup fracture space and reduce interfacial tension between fluids delivering a more affective stimulation.

Table 1 summarizes the RTA findings. Both pilot wells (Reference and Surfactant wells) showed very similar pre-injection EFL, consistent with the fact that both wells are from the same area and were completed with identical designs. Also, both wells showed improved performance after stimulation and with that a change in EFL values. The calculated increase in effective fracture length ranges from 7 to 41%. This seems a good quantifier of well improvement. However, the Surfactant well show more improvement (41%) than the reference well (7%).

TABLE 1
RTA effective fracture length (EFL) changes
for the Reference and Surfactant wells.

	Effective	Effective
	fracture length	fracture length	Effective fracture
Well	Pretreatment (ft)	Post treatment (ft)	change (%)

Reference	96,000	103,000	7
Surfactant	95,000	134,800	41

In summary, the wells improvement after injection can be modeled by increasing fracture area (RTA method). The Surfactant well shows a larger incremental change in effective fracture length compared to the Reference well. In addition, the surfactant well exhibits higher pressure trends, and PI, after injection as a signpost of increased fractured area.

Tracers Results: FIG. 16A-16C summarizes tracer results for the injection pilots in unconventional wells (Reference and Surfactant). Specifically, tracer breakthrough in offset wells, tracer flowback in treated wells, and tracer mass recovery were monitored for the Reference and Surfactant wells. A lesson from tracer response was the significant interwell connectivity between hydraulicly-fractured wells, as seen in tracer recovery bubble maps in FIG. 16A where tracer breakthrough is observed in multiple offset wells up to approximately 2000-ft away. Additionally, tracer and water breakthrough in primary offsets was observed during the injection period. An example is shown in FIG. 16B where tracer breakthrough in both primary offsets of the Reference well occurred in about 2.5 days (during injection period) and tailed off after injection stopped.

Considering the short injection time and the fast breakthrough, this interwell connectivity is evidence for interlinking hydraulic fracture network, confirming a horizontal fracture half-length of nearly 440-ft for multiple wells. This information along with cumulative oil production could be used to assess the efficiency of completion size and better design it for optimal cost and primary oil production while reducing fracture driven interactions (FDIs) to parent wells.

Another learning from the tracer data was the confirmation of enhanced imbibition by surfactant compared to brine. Two simultaneous observations were required for such confirmation: lower tracer mass recovery and higher oil production uplift, both of which were observed in the Surfactant well as seen in FIG. 16C and FIG. 11 (see previous section). The cumulative tracer mass recovery for the Reference well was approximately 37% while it was close to 14% for Surfactant well. The significantly lower tracer recovery in Surfactant wells is accompanied by higher oil recovery, indicating a successful enhanced imbibition by surfactant where oil is mobilized to flow to surface, and water is locked away in-situ. Given the similarity of treatment volume, interwell connectivity, soaking time, and de-watering method for the Reference and Surfactant well, the higher tracer recovery in Reference well indicates that water treatment is less effective than surfactant treatment.

Surfactant Results: Surfactant performance hinges on a) the integrity of the chemical package during flow through the hydraulic facture network and neighboring offset wells and b) preferential adsorption to alter wettability and clean fracture surface and proppant pack while soaking in the treated wells. To confirm these expectations, surfactant breakthrough in offsets and its flowback in the treated well were monitored and compared to tracer (FIG. 17A-17B). As seen in FIG. 17A, surfactant arrives at a vertical observation well (distance-200-ft) at the same time as tracer, confirming the integrity of chemical slug during flow through the fracture system. This will rule out chromatographic separation and surfactant precipitation as deterring factors at shorter time frames (i.e., weeks) of flow in fracture network. For longer time frames (i.e., months), surfactant flowback in the Surfactant well lags that of tracer (FIG. 17B). This is expected as surfactant adsorbs while tracer is inert, and beneficial since surfactant consumption leads to higher oil production and lower surface-handling challenges such as emulsion production. Despite the successful application of surfactant for stimulating unconventional wells, the surfactant SA&O could be improved. For example, measuring surfactant concentration in field samples is challenging due to non-unique calibrations. This could lead to mass balance errors for the slug or individual components and prevent further optimization of the surfactant package. Another aspect is readiness of demulsifiers in the field to mitigate risk of emulsion breakthrough in primary offsets if needed (Pinnawala et al., 2021).

Salinity: Salinity was measured in the treated well (during flowback) and in offset wells (during injection and flowback) to determine mixing with formation brine. This mixing occurs during the flow of injected water (through fractures and through well lateral) and during the shut-in of the treated well. FIG. 18A-18B shows the salinity data for the Reference well and one of its primary offsets. Salinity and tracer breakthrough in the primary offset in 2.5 days (i.e., during the injection period). A good correlation between salinity and tracer response is observed in both wells. More importantly, in the case of offset well, the mixing occurs during flow through fracture system as well as merging with water produced from untreated sections of the horizontal well. In the case of the Reference well, which is shut-in before flowback, brine mixing indicates a lack of equilibrium in the horizontal well and “water sloshing” or water moving back and forth within the fracture system.

In summary, this example evaluated and expanded on the ability of surfactants added to stimulation fluids on improving oil recovery in horizontal unconventional wells. Before pilot execution, reservoir modeling was performed to assess the possible outcomes and evaluate proposed recovery mechanisms resulting in positive indications that hydrocarbons can be recovered by the proposed stimulation technique.

A pilot was conducted in which two wells were stimulated at their mid-life by injecting close to 50 Mbbls of water, with surfactant in one well, soaking for few days and putting back on production. The pilot design included chemical selection by laboratory studies and treatment volumes by reservoir simulation. To have a valid baseline for comparison, one of the two pilot wells was stimulated with only water (Reference well) and the other with water plus surfactant (Surfactant well), and the two wells selected had identical completion design, similar productions dates and from the same geological area. Pilot execution details were noted, and fluid volumes, rates, and surfactant concentrations were discussed. Moreover, a robust surveillance analysis and optimization plan was proposed and executed to assess not only production changes before and after stimulation, but also to assess the proposed recovery mechanisms.

To that end, PI, RTA, DCA, tracers, surfactant flowback and salinities were used and evaluated to compare both pilot wells and create a clearer picture of the technology potential and applicability. The pilot results showed that the Surfactant well recovered more oil, exhibited a higher EUR, and had a greater change in effective fracture length than the Reference well. Also, tracer results showed higher tracer concentrations in the Reference well flowback as a signpost of a less effective treatment. These results are consistent with the Conceptual Models. For the results obtained, it can be concluded that stimulation with surfactant additives could improve oil recovery by wettability alteration, fracture cleanup and IFT reduction, maximizing well performance after stimulation. The next steps include continuing piloting these efforts in a bigger set of wells honoring the workflow and SA&O discussed in this example.

CONCLUSIONS

The results from this work have practical implications on the design of stimulating fluids to improve oil recovery in unconventional reservoirs. Unlocking this technology could increase unconventional wells recovery factors and extend the life of shale and tight assets. This study has concluded:

• • 1) A systematic workflow was described and implemented to characterize the design of chemical stimulations in unconventional horizontal wells. This workflow enables a consistent and efficient way to plan, execute and monitor field tests.
  • 2) A part of the testing and implementing technology such as chemical stimulation in unconventional reservoirs with factory-like operations involves a robust design and pilot planning and execution, including confidence in test results to support proof of concept, prior to its large-scale implementation field wide.
  • 3) The SA&O plan and execution with details of signposts help assess the potential impact with clarity, given the many parameters and uncertainties involved. The carefully designed SA&O enabled an effective assessment for the proof of concept associated with first principles (i.e., conceptual model), addressing key physics/mechanisms involved.
  • 4) The potential effect of chemical treatment tested here shows more pronounced impact or beneficial results as compared to that of the reference case only using water as injection fluid. The Surfactant well shows higher productivity index post-treatment, slower decline rates and more incremental EUR uplift than the Reference well (with water injection only).
  • 5) A systematic simulation workflow using RTA trained fracture-swarm model was developed that is quick and easily scalable to multiple wells. Workflow was tested and was found to be easy to history-match for both the reference and surfactant stimulated well. A 10-fold increase in the matrix-fracture transmissibility was speculated using the simulation model.
  • 6) Tracer breakthrough was observed in multiple offset wells up to approximately 2000-ft away. Additionally, tracer and water breakthrough in primary offsets often observed during injection period, confirming an interlinking hydraulic fracture network with a horizontal fracture half-length of nearly 440-ft for multiple wells.
  • 7) Enhanced imbibition by surfactant compared to brine was confirmed by two simultaneous observations: higher oil production uplift and lower tracer mass recovery in the Surfactant well compared to the Reference water well. Given the similarity of treatment volume, interwell connectivity, and de-watering method, surfactant stimulation is more effective than water injection.
  • 8) Existing unconventional well stimulation with surfactant additives could improve oil recovery by wettability alteration, fracture cleanup and IFT reduction, maximizing well performance after stimulation.
  • 9) The proposed workflow proven to be general and robust to enable expansion of the learnings to apply to other shale and tight basins, with tailoring need to account for local effects (rock, fluid, reservoir characterization, and completion effects, etc.).

Example 2: Piloting of Chemical EOR in Unconventional Liquid Reservoirs

Aspects of this example are described in Salman, M. et al. “Piloting of Chemical EOR in Unconventional Liquid Reservoirs” Unconventional Resources Technology Conference (URTeC): 4260303 (DOI 10.15530/urtec-2025-4260303), which is incorporated by reference in its entirety.

Developing unconventional shale & tight liquid reservoirs has become a global trend in recent years. This development relies on primary depletion, which uses the initial reservoir energy to drive oil to a well through fracture networks created by hydraulic fracturing. Primary production from unconventional reservoirs results in high fluid rates that rapidly decline and stabilize at low levels for many years. Chemical enhanced oil recovery (EOR) is a technique that aims to improve hydrocarbon recovery from reservoirs by injecting chemicals that reduce interfacial tensions, change wettability and improve oil relative permeability. Chemical EOR has been widely applied in conventional reservoirs and its application in unconventional reservoirs is challenging and requires careful design and execution. Results from multiple surfactant injections in unconventional assets are shown. Results from ten producing wells show a recovery ranging between 5-40 Mbbls. Chemical selection methods and criteria is discussed. Finally, execution planning, surveillance and critical operational details required for successful chemical EOR in unconventional reservoirs are summarized. The results illustrate the applicability of chemical EOR in unconventional reservoirs. With appropriate implementation chemical EOR can potentially increase ultimate recovery factors and extend field life.

Chemical EOR requires scaling from the laboratory to the field, typically achieved through appropriately sized and designed pilots. Given the cost of injected chemicals, these carefully designed pilots identify various subsurface and surface uncertainties, allowing practitioners to develop full-field scale-up plans. Learnings from conventional reservoirs were applied to design and implement multiple pilots in an unconventional reservoir. Unlike interwell testing in conventional reservoirs, unconventional reservoirs involve injection and production from the same well. In some instances, well connectivity can be achieved and observe offset well impact from chemical injection.

Chemical EOR was extremely popular in the 70's through the early 90's. Gogarty reviewed the 1960-1970 wave of surfactant EOR pilots in conventional reservoirs, covering commercialization aspects from lab to field scale. See Gogarty, W. B. 1976. J Pet Technol 28: 93-102. Pursley and Graham (1975) described pilot work in the Borregos field, reporting challenges with surfactant adsorption and process sweep efficiency. See Pursley, S. A., and H. L. Graham. 1975. J Pet Technol 27: 695-700. Gogarty and Davis (1972) introduced the Maraflood process, which used a surfactant slug to recover oil through displacement, and described field experience in several tests and design evolution. See Gogarty, W. B., and J. A. Davis. 1972. SPE Improved Oil Recovery Symposium. Tulsa, Oklahoma, USA. Earlougher et al. (1974, 1975) reported progress on the Maraflood process, citing scale-up plans and a pivot towards designing fluid systems to meet economic constraints while operating under a range of field conditions. See Earlougher, R. C., et al., 1974. SPE Midwest Oil and Gas Industry Symposium. Indianapolis, Indiana, USA, and R. C. Earlougher, Jr., et al., 1975. SPE Rocky Mountain Regional Meeting. Denver, Colorado, USA.

French and co-workers (1973) reported progress on a surfactant tertiary oil recovery process deployed in the Benton Field, Illinois, and described how they addressed injection well performance and emulsions at observation and production wells, recommending tailoring slug design for compatibility with formation water to reduce emulsions and precipitation. See French, M. S., et al., 1973. J Pet Technol 25: 195-204.

Vinatieri (1980) studied emulsions for a surfactant flood pilot in Osage County, Oklahoma, focusing on macroemulsions generated by the process. See Vinatieri, James E. 1980. SPE J 20: 402-406. The work suggested that surfactant pilots from an oilfield operations perspective require proper demulsifier screening, mechanisms for destabilization, and emulsion detection. Bragg et. al (1982) reported field pilot results at the Loudon field for a surfactant flood effective in the presence of high-salinity formation water (104,000 ppm total dissolved solids [TDS]). See Bragg, J. R., et al., 1982. SPE Enhanced Oil Recovery Symposium. Tulsa, Oklahoma, USA. They mentioned challenges with emulsions initially breakable by adjusting temperature at the facility heater treater but eventually needing demulsifiers due to water-in-oil issues. Reppert and co-workers (1990) shared updates in the Loudon field, reporting improvements in emulsion handling through careful temperature control and an optimized two-phase separator with the potential to recycle surfactant-laden produced water for treatment at scale. See Reppert, T. R., et al., SPE/DOE Enhanced Oil Recovery Symposium. Tulsa, Oklahoma, USA. Duke (1994) discussed the limitations of conventional oilfield processing equipment paired with commercially available demulsifiers for a surfactant-polymer project, detailing a switch to an EOR-grade demulsifier which improved separation quality and economics. See Duke, R. B. 1994. SPE Advanced Technology Series 2: 214-221.

The fall in oil prices in the early 90's made chemical EOR unpopular, and the efforts picked up again in the 2000's with polymer flood injections offshore in Dalia (Morel et al., 2012), polymer flooding pilots and projects in Oman, Canada, India and United Kingdom (Al-Sulaimani et al., 2024, Delamaide, 2021, Prasad et al., 2014, and Poulsen et al., 2018). The surfactant polymer pilot in Indonesia (Masduki et al., 2020) showed that surfactants could significantly increase oil rates. A goal is to show that oil rates can be increased by surfactant injection in unconventional reservoirs.

In a paper, (Alvarez, Johannes O., et al., 2023. SPE/AAPG/SEG Unconventional Resources Technology Conference. Denver, Colorado, USA (“Alvarez, et al., 2023”)) the use of surfactant additives in stimulation fluids to enhance oil recovery in shale and tight reservoirs was demonstrated. The study focused on designing and field-testing stimulation fluids that maintain clean fractures with aqueous stable surfactant mixtures. Such clean fluids penetrate deeper into the stimulated area and mobilize more hydrocarbons by altering rock wettability and lowering interfacial tension (IFT). A paper described the use of reservoir modeling, laboratory tests for surfactant selection, and field testing on two wells. The results showed that the well stimulated with surfactants (Surfactant well) recovered more oil and exhibited a higher estimated ultimate recovery (EUR) than the wells stimulated only with water (Reference well). Specifically, the Surfactant well increased its oil EUR by 7.8% compared to the Reference well's 2.3% increase. The Surfactant well produced an additional 32 Mbbl of oil over 365 days, while the Reference well produced an additional 8 Mbbl of oil. Tracer results indicated higher tracer concentrations in the Reference well flowback, suggesting a less effective treatment. The study concluded that surfactant additives can improve oil recovery by wettability alteration, fracture cleanup, and IFT reduction, leading to higher productivity and slower decline rates compared to water-only treatments.

While a few authors (Hoffman, B. Todd. 2023. “Chapter 7—Enhanced oil recovery in unconventional reservoirs.” In Recovery Improvement, 365-426. Gulf Professional Publishing; Chen et al., 2023; Alvarez et al., 2023) catalog advances in surfactant EOR in unconventional reservoirs, several notable works have emerged since. Singh et al. (2024) share lessons learned from field implementations of foam EOR in conventional and unconventional reservoirs, suggesting a workflow that includes candidate selection, chemistry selection, modeling, and field implementation in collaboration with several operators. See Singh, Robin, et al., 2024. SPE Improved Oil Recovery Conference. Tulsa, Oklahoma. They recommend best practices such as well integrity assessment and flow assurance.

Ataceri et al. (2024) report progress on two field trials on late-life wells in the Eagle Ford, implementing a bullhead injection design of 0.22 wt % surfactant at five times the fracture void volume with and without diversion at 15 bpm injection. See Ataceri, I. Z., et al., 2024. SPE Improved Oil Recovery Conference. Tulsa, Oklahoma, USA. They suggest that recovery effects will be stronger on younger wells with diversion. Pearl et al. (2024a) review progress on pilot trials in the Bakken with biosurfactant bullhead injections at 3 Mbbl total fluid at a 13-15 bpm injection rate, reporting success on 11 out of 15 late-life trial wells. See Pearl, M., et al., 2024. SPE Annual Technical Conference and Exhibition. New Orleans, Louisiana, USA. For wells that performed poorly, they suspect that fluids treated low-pressure zones rather than the entire lateral. They also suggest that rigless work is more favorable and that diversion may help treat a larger portion of the lateral. Pearl et al. (2024b) report additional success with biosurfactant trials in the Bakken and the Permian. See Pearl, Megan R., et al., 2024. SPE/AAPG/SEG Unconventional Resources Technology Conference. Houston, Texas, USA. The Bakken case (2.7 Mbbl total fluid, 10-14 bpm bullhead injection) showed a better production response compared to conventional surfactants, while the Permian case (5 Mbbl total fluid, 3-5 bpm bullhead injection, 7-day shut-in time) saw a 30% increase in oil volume.

Pinnawala and co-workers described a workflow to design and optimize treatment fluids with surfactants for unconventional reservoirs. See Pinnawala, Gayani W., et al., 2024. “Fracture-Fluid Chemistry Optimization to Improve Hydrocarbon Recovery for Shale and Tight Assets.” SPE Improved Oil Recovery Conference. Tulsa, Oklahoma, USA. (“Pinnawala et al. (2024a)”). They emphasized fluid compatibility with friction reducers, acid spearheads, and production chemicals for blends of anionic and nonionic surfactants. By adjusting the ratios of anionic and nonionic surfactants in the blend, they developed several surfactant blends to target a wide operating salinity environment, ensuring compatibility with unconventional reservoirs of varying formation salinity and temperature. They also discuss a QA/QC workflow for developing the same surfactant blends tailored for field deployment, which minimized liquid additive pumping risks and maximized long-term stability. See Pinnawala, Gayani W., et al., 2024. “Chemical EOR Field Support Including Surfactant Blending Studies and Quality Control for Shale and Tight Assets.” SPE Improved Oil Recovery Conference. Tulsa, Oklahoma, USA.

Palayangoda and co-workers (2024) described the development and validation of dual-function defoaming and demulsifying agents tailored for chemical EOR through the use of water-soluble partitioning agents. See Palayangoda, Sujeewa S., et al., 2024. SPE Improved Oil Recovery Conference. Tulsa, Oklahoma, USA.

Described herein is pilot work executed on a set of wells in an unconventional asset and the lessons gained from these pilots. Laboratory methods are presented to select a robust surfactant for a target reservoir. Methods to successfully execute chemical injections are also outlined. Execution and well performance results are presented, with appropriate baseline surveillance, and flowback management. Finally, opportunities for future chemical EOR improvement in unconventional reservoirs were highlighted.

Experimental

Laboratory Tests and Surfactant Selection

Pinnawala et al. (2024a) describe the laboratory selection methods in detail. Laboratory experiments developed chemical blends to manage reservoir salinity and temperature and achieve appropriate interfacial tensions.

Surfactant Aqueous Stability and Phase Behavior

Aqueous stability tests were conducted to evaluate the compatibility of the surfactant mixture with the injection and formation fluid. The aqueous stability limit refers to the maximum salinity at which the aqueous solution remains clear (aqueous stable solution) before it becomes hazy or cloudy (aqueous unstable solution) under given conditions i.e. reaches cloud points. For the given surfactant mixture, the aqueous stability limit will change based on temperature, brine composition, and other oil field chemicals injected with the surfactant package. The target is for the aqueous stability limit to be at least 10% higher than the target salinity limit.

Microemulsion phase behavior tests were performed to quantify the interaction between surfactants and target oil under specific reservoir conditions. The method for phase behavior experiments is described in literature (Levitt, David B., et al., 2009. SPE Res Eval & Eng 12: 243-253; Flaaten, Adam K., et al., 2009. SPE Res Eval & Eng (12): 713-723; Zhao, Ping, et al., 2008. SPE Symposium on Improved Oil Recovery. Tulsa, Oklahoma, USA; and Lu, Jun, et al., 2014. SPE J. 19: 1024-1034). For phase behavior experiments, aqueous surfactant solutions were combined and oil in glass pipettes (bottom-sealed 5 mL graduated borosilicate glass pipettes marked in 1/10 ml increments) or vials. Then, the samples were mixed and placed them in an oven set to the target reservoir temperature. The sealed samples over time for interphase behavior were observed. The goal was to obtain a clean interphase without any viscous emulsion. The microemulsions are also expected to separate into excess phases in less than 24 hours, which exhibiting low viscosity.

Contact Angle Measurements

Ramé-hart Automated Goniometer 590-G1 was used for measuring contact angles. A rock chip with a diameter of 0.5 inches and a thickness of 0.25 inches was used as the solid phase. The chip surface was polished to minimize surface roughness and then aged it with crude oil at reservoir temperature for more than 10 days to achieve consistent wetting characteristics before testing. The restored chips were placed in an aging cell filled with either formation brine or surfactant solution at reservoir temperature for soaking tests. The contact angle of the chips after the soaking test was measured using the captive bubble method at different times to study how the wettability of the rock changes over time induced by brine or surfactant.

IFT Measurements

A Grace M6500 Spinning Drop Tensiometer was used to measure microemulsion-oil IFT at reservoir conditions. Surfactant and oil were mix in vials and let them equilibrate for a few days. The excess phases are sampled and put in a spinning drop tensiometer to measure IFT. The IFT is measured for dead oil and varying brine salinity and surfactant concentrations.

Core Injection Test

A core injection test system was used for core scale imbibition tests. This system could be used to run core injection tests at elevated temperatures (up to 300° F.) and high pressure (up to 3,000 psi) to mimic reservoir conditions. Reservoir cores with a length of 7.25 inches and a diameter of 2 inches for the core injection test were used. The cores were first restored at reservoir temperature and pressure with crude oil before using them for the imbibition test. Either formation brine or surfactant solutions were introduced into the fractures to conduct counter-current imbibition. During the test, oil production by brine or surfactant solution imbibition into the core over time was measured. Due to the low permeability of the rock, core imbibition tests took up to 3 months.

Execution Design, Planning, Surveillance, and Performance

The effects of depletion (time on production), shut-in time, and surfactant concentration in a focused black oil area were tested. A candidate selection criterion was created that targets wells with stable production, sufficiently high oil rate, free from nearby development activity to minimize well interferences, and engineered artificial lift systems capable of dewatering a large treatment bank. This was then paired with an execution design that includes pre-work, injection, shut-in, flowback, and post-treatment monitoring.

Candidate Selection

10 wells in an unconventional asset were selected that have black oil PVT properties for trials. Such selection was done to continue work presented by Alvarez et al., (2023). Table 2 shows the oil, produced water, and formation temperature properties for the trial wells. All wells had stable production before treatment to establish baseline decline. Chosen candidates were spatially far apart to avoid well connectivity and response overlap. Additionally, wells that were far from drilling and frac operations were chosen to prevent early uplift termination. Continuous gas lift and electric submersible pump (ESP) wells were selected so that dewatering times could be minimized. Table 3 describes the landing zone, completions design, and direct distance (lateral and vertical) to each candidate's nearest offset neighbor.

TABLE 2
Grouped landing zone fluid properties for candidate wells.

Landing		Reservoir	Produced water	Formation
zone	Oil API	Fluid Type	×1000 TDS, ppm	temperature, ° F.
Bench X	41	Black Oil	144-153	150-155
Bench Y	40-43	Black Oil	109-114	153-158
Bench Z	40-44	Black Oil	74-124	156-163

TABLE 3
Well candidate completions details.

Well ID	Landing zone	Nearest neighbor distance, ft

1	X	500
2	X	900
3	X	700
4	Y	900
5	Y	900
6	Z	700
7	Z	500
8	Z	900
9	Z	700
10	Z	700

Design

With the candidates selected, a design framework was developed that examines treatment intensity, surfactant concentration, and well depletion. All wells were treated with brackish water as carrier fluid with a TDS range of 2,800 to 22,100 ppm. Treatment intensity was define as the carrier fluid load used for the treatment, normalized by the lateral length. Low treatment intensity is defined as 2.0-3.0 barrels of water per foot (BW/ft). In contrast, high treatment intensities (defined as 3.0-6.0 BW/ft) can positively impact offset wells if designed correctly. When selecting treatment intensities, consider well spacing, completion designs, artificial lift optimization, and offset management practices. Surfactant concentrations were also categorize above 3,000 ppm as high and below as low. Table 4 describes the job treatment designs for the selected candidates.

The jobs were designed to maximize injection rates while considering friction and surface pressure limits, ensuring to stayed below the fracture gradient to maximize treatment potential (Paccaloni, Giovanni. 1995. SPE Prod & Fac 10: 151-156). Job design was approached by considering the following factors:

Injection setup: The same field injection setup was used to bullhead treatments described in previous work, with a few design changes (Alvarez et al., 2023). The frac pumps were upsized from triplex to quintuplex to handle jobs with injection rates exceeding 20 bpm and sized frac iron accordingly while staying below erosional limits.

Injection water: A network of lay flat lines and transfer pumps were used to deliver the required volumes from a nearby brackish water frac pond. Brackish water salinity varied from well to well based on regional sourcing and pond conditions. All water was confirmed as usable for injection prior to the start of the treatment.

Biocide: a minimum of 0.1 gpt biocide was dosed to mitigate microbial corrosion and potential souring from the injections. The biocide was dosed into the frac tanks on location to ensure thorough mixing and treatment before dosing with surfactant.

Soak time: While not a primary objective of this work, soak time was ensured on all the treated wells were based off laboratory studies on time required to alter wettability at a minimum. In most cases, the time was based off rig work required to re-install an ESP for safe start-up.

TABLE 4
Well treatment details.

				Average
	Years	AL type		chemical	Injection	Soak
Well	online at	at	Treatment	concentration,	rate,	time,
ID	treatment	treatment	intensity	ppm	bpm	days

1	0.5	ESP	High	5,900	<20	5
2	1.5	ESP	Low	3,700	<20	8
3	2.5	ESP	High	2,300	>20	16
4	3.0	ESP	Low	2,100	>20	5
5	1.0	ESP	High	5,500	<20	9
6	1.0	GL	High	4,000	<20	12
7	1.5	GL	Low	4,600	<20	21
8	0.5	ESP	High	2,600	>20	5
9	1.5	ESP	Low	2,000	<20	3
10	0.5	ESP	Low	2,700	>20	5

Planning and Surveillance

FIG. 19 depicts the execution workflow for the 10 wells in the trial. The sequence of activities ensures that risk is minimized as best as possible to the candidate well, its offset wells, and the central tank battery (CTB) while ensuring maximum value of information.

The following factors were considered in the planning and surveillance approach:

Well integrity checks: the asset integrity and area subsurface team collaborated to validate the production chemistry health of the treated well, focusing on bacteria, iron sulfide scale, and corrosion. For gas lift wells, static and flowing bottom hole surveys were conducted with gauge ring runs to confirm tubing integrity.

Facility health checks: To ensure the vessels in a facility were in good condition, the maintenance and planning team scheduled thermographic surveys in areas prone to process upsets to evaluate vessel conditions pre-treatment. Vessels with build-up would typically be addressed during planned field shutdowns for maintenance and upgrades; however, the timing of the work may not coincide with a treatment. FIG. 20A-20B shows two examples of moderate solids (FIG. 20A) and severe solids (FIG. 20B) for 3-phase separators managing commingled production. Example A would require minimal effort during flowback; however, example B would require additional precautions taken during execution planning for field management during injection and flowback.

Realtime signals including rates and pressures: Calibrated, functional rate and pressure gauges on wells and production facilities are critical for monitoring and well performance. The same conditions apply to gauges and meters deployed during injection.

Offset well management: Early execution approaches to offset well detection primarily involved factoring in nearest neighbor distance to offset wells from the injector. Subsurface features often lead to unwanted surprises; therefore, a geological risk survey is included for wells and highlight faults and other features that would induce offset well communication. Offset wells in the set produced through the treatment with real time monitoring. The monitors set flags on artificial lift and facility vessel trend changes, notifying field personnel to react accordingly. Chemical tanks were set and selected flowback chemicals to manage emulsions and foam, adjusting treat rates to maintain production uptime.

Flowback management: flow assurance chemicals were dosed for treated wells with high foam or emulsion tendencies during flowback until the untreated wellhead response meets production facility specifications.

Well test scheduling: Lastly, frequent well testing was ensure with well test schedules to capture early production responses and conduct follow-up retrospectives on jobs to capture lessons learned. Weekly well tests were chosen at a minimum for treated and offset wells for 3 months, followed by biweekly to monthly well tests.

Well Performance Analysis

In a previous publication (Alvarez et al., 2023), tracers, rate transient analysis (RTA), productivity index (PT) analysis, and decline curve analysis (DCA) with in-house and commercial software were used to confirm the validity of the treatment response using multiple signposts. This work focused on DCA responses, particularly around net uplift for the full set of wells. Net uplift was defined as the difference between gross uplift and the baseline DCA response, including periods when the treated well was constrained during the initial dewatering phase.

In this example, three wells were explored in the set to confirm multiple signposts in addition to DCA. RTA (Kurtoglu, Basak, et al., 2015. Abu Dhabi International Petroleum Exhibition and Conference. Abu Dhabi, UAE; Yadav, Himanshu, et al., 2017. SPE Hydraulic Fracturing Technology Conference and Exhibition. The Woodlands, Texas, USA) was applied and for the first time multiphase flowing material balance or MFMB (Thompson, Leslie G., et al., 2022. SPE/AAPG/SEG Unconventional Resources Technology Conference. Houston, Texas, USA; Young, Steven, et al., 2023. SPE/AAPG/SEG Unconventional Resources Technology Conference. Denver, Colorado, USA) as an additional signpost. The data was processed using the workflow defined by Clarkson, Christopher R. 2021. Unconventional Rate-Transient Analysis. Gulf Professional Publishing and applied bottomhole pressure corrections factoring in changes in artificial lift installation through the life of the analyzed wells (Carlsen, M., et al., 2024. SPE/AAPG/SEG Unconventional Resources Technology Conference. Houston, Texas, USA).

Results & Discussion

Laboratory Tests and Surfactant Selection Results

The results and observations from laboratory experiments to evaluate surfactant performance and recommend surfactants for field testing are presented below:

Surfactant Aqueous Stability and Phase Behavior

A major challenge in developing a surfactant formulation is finding an aqueously stable solution at conditions higher than the reservoir formation brine, which was around 100,000 ppm at reservoir temperature (165° F.). the CS-1 formulation for this application was developed which has an aqueous stability up to 125,000 ppm TDS, 30% higher than the target reservoir conditions. FIG. 21 shows the aqueous stability test samples using the surfactant formulation CS-1. The aqueous stability of this surfactant decreases with an increase in salinity and temperature.

Phase behavior experiments with the formulation show no viscous interfaces up to 130% brine (˜125,000 ppm TDS) at reservoir conditions, as seen in the phase behavior tubes with the CS-1 formulation in FIG. 22. These samples also equilibrate to stable microemulsions in less than 24 hours.

Contact Angle Measurements

FIG. 23A-23B shows the contact angle measurement results for rock samples from target shale. The rock chips was soaked with surfactant solution at various times, from 0 to 22 hours at reservoir temperature. Surfactant solutions were assessed with concentrations ranging from 0 to 0.3%. The results showed that the initial rock was oil-wet with a contact angle of 140-160 degrees (oil-wetness). After soaking the rock chips with surfactant solution for a certain time, the contact angle quickly decreased to less than 90 degrees (water-wetness), depending on the surfactant concentration. The lowest contact angle achieved was around 20-30 degrees, indicating that the rock was successfully transformed from strongly oil-wet to strongly water-wet with surfactant application.

IFT Measurements

FIG. 24 shows the IFT response for CS-1 using a spinning drop tensiometer. CS-1's IFT reduction needs to be optimized to improve imbibition recovery process. Target IFT is around 0.1-10 mN/m. The results show that the IFT between the water and crude oil phase is around 20-30 mN/m for brine and 1-5 mN/m for a 0.15% surfactant solution. An increase in salinity results in a reduced IFT. The IFT results indicate that the selected surfactant meets expectations for improving the imbibition process.

Core Injection Test

Core injection tests were used to further optimize the surfactant injection performance for the selected shale. These tests allowed us to validate surfactant imbibition behavior and oil recovery potential. Surfactant performance was evaluated against the brine baseline imbibition recovery to confirm improved oil recovery potential. Both secondary and tertiary oil recovery performance with the core test system was assessed. FIG. 25A-25B shows the core imbibition test results for injection brine (first part of the tertiary oil recovery experiment) as well as the core imbibition test results for 0.3% CS-1 surfactant solution injection. The oil recovery by injection brine (no wettability alteration and no IFT reduction) is only around 7%. Moreover, the oil recovery by surfactant solution significantly increased up to 45%, which is about 38% higher than by injection water, indicating that wettability alteration from oil-wet to water-wet (contact angle is around 30-40 degrees) and IFT reduction from around 20-30 mN/m to around 1 mN/m can drastically improve water imbibition potential. Similar oil recovery (˜47%) was observed in secondary surfactant injection. The results confirm that using surfactant injection can stimulate oil recovery in both tertiary and secondary methods for shale and tight rock reservoirs.

Based upon the lab results it was shown that changing wettability and interfacial tension can successfully enhance imbibition and recover oil from the rock matrix. While some recovery can be attributed to changes in capillary pressure, additional detailed work is required to better understand the relative contribution of IFT reduction and wettability change.

Well Performance Analysis Results

The injection conditions for the 10 pilot wells were within surfactant operating limits to maintain aqueous stability at the given concentrations due to the resulting salinity and temperature from subsurface mixing of injection and formation waters and near wellbore cooling during injection. The results for all wells are summarized in Table 5. Additionally, the relationships between net oil uplift, soak time, surfactant concentration, treatment intensity, and offset interaction versus nearest neighbor distance were examine in FIG. 26A-26E.

TABLE 5
Well treatment response details.

	Net uplift treated	Total uplift (treat	Offset well
Well ID	well, MBO	and offset), MBO	communication?

1	38	38	Yes
2	25	25	—
3	15	15	—
4	6	6	—
5	20	20	Yes
6	5	5	Yes
7	14	14	—
8	23	23	—
9	32	32	Yes
10	24	28	Yes

Artificial lift. Another component of well deliverability is the design of the well and its equipment, specifically its vertical flow performance (Economides, Michael J., et al., 2015. Petroleum Production Systems, 2nd Edition. Prentice Hall). For the gas lift well candidates, the wells were completed with conventional valves, leaving little room to modify the gas lift design to account for high water cut during dewatering. The ability to see an early response based on a treatment design depends heavily on the selected well candidate and the installed artificial lift's liquid lifting capacity. The stronger the lifting capacity, the less attenuated the response during return to production. This is evident in the oil response for Wells 1 and 5 compared to Well 7, where the time required for oil to reach baseline was 11, 9, and 29 days, respectively. The limitations of the conventional gas lift design on Well 7 restricted the maximum liquid rate achievable to 800-900 bbl/d, compared to the 1,800-2,000 bbl/d capacity that Wells 1 and 5 could deliver. This indicates that treatment designs, particularly treatment intensity, should be thoroughly studied alongside the well's artificial lift design for cyclic surfactant or huff-and-puff processes.

Time online or depletion. FIG. 26A shows a favorable relationship between net oil uplift and depletion for a selected well candidate when normalizing vertical flow performance effects. Higher available well energy early in a well's life yields a stronger response, while lower well energy favors treating depleted fractured rock. Treatment intensity's relationship to well depletion should also be considered when designing chemical EOR treatments for unconventional reservoirs.

Soak time. Soak time should be designed to maximize the selected surfactant system's ability to alter wettability and reduce IFT, thereby mobilizing oil through spontaneous imbibition (Alvarez, J. O., et al., 2018. SPE J. 23: 2103-2117). Although FIG. 26B does not show an apparent trend, a carefully designed surfactant package can recover additional oil without negatively affecting the reservoir during extended shut-ins.

Surfactant concentration. At first glance, the highest recovery corresponds to the highest surfactant concentration in FIG. 26C, suggesting a positive relationship between recovery and surfactant concentration. While this is true in conventional cases, engineers should also consider adsorption effects related to rock properties and the potential detrimental effects of excess surfactants in the subsurface and during production (Sharma, Mukul M. 2019. “Formation Damage.” In Acid Stimulation, by Syed A., Kalfayan, Leonard, Montgomery, Carl T. Ali; Belhaj, A. F., et al., 2020. J Petrol Explor Prod Technol 10: 125-137; Massarweh, Osama, et al., 2020. Energy Reports 3150-3178). The ideal approach is to select a surfactant concentration within characterized flow assurance limits for the target production environment.

Treatment intensity and offset interaction. While the need to explore the effects of treatment intensity in relation to depletion and artificial lift was previously discussed, the response in treatment intensities in FIG. 26D is not significant without considering offset interaction responses and nearest neighbor distance from FIG. 26E. High treatment intensity at closer well spacing can induce offset interaction. Among the wells with offset interactions, only one (Well 10) showed positive uplift attributed to offset wells. There is likely a relationship between treatment intensity, completions, geology, and nearest neighbor distance that causes offset interaction. Designing a chemical EOR treatment in unconventional liquid reservoirs can take one of two approaches: minimize offset interaction while focusing on increasing the treated well response or maximize offset interaction to increase treatment efficiency for a given area. Both approaches have merits and warrant further investigation.

Case Study 1: Well 1 (Bench X, ESP)

Well 1 was chosen as a candidate because of a reactive well failure caused by the installed ESP grounding on high motor temperature shut down. Operations were coordinated to conduct the surfactant treatment while pulling the ESP to allow for casing injection and optimized treatment rates. After completing the treatment, a new ESP was installed, allowing for a 5-day shut-in soak time. During the injection, the well communicated with immediate offsets, and a neutral effect was observed on the offset wells from the treatment. The well was brought online and saw high initial water production, returning to baseline oil production after 5 days. FIG. 27 shows the oil production baseline and post-treatment response for Well 1. The post-treatment response was sustained for over a year, confirming the treatment's success.

To confirm the treatment's success, Rate Transient Analysis (RTA) was applied and Multiphase Flowing Material Balance (MFMB) to the pre- and post-treatment production history. FIG. 28A-28B illustrates the pressure-normalized oil rate (or productivity index PI, left) and mass rate-normalized density change response for Well 1. An improvement was observed in PI from the treatment, with a higher PI compared to pre-treatment levels. By focusing on linear flow regime identification to detect changes in the linear flow parameter (LFP, or Ak) using the oil phase on RTA, a 14% improvement in LFP was noted.

The MFMB response also shows a higher contacted pore volume, as indicated by the shallower slope compared to the pre-treatment response. A 68% improvement was estimate in contacted pore volume (OOIP). This increase in contacted pore volume and LFP can be attributed to the surfactant's ability to modify fluid-fluid and rock-fluid interactions in the subsurface, providing access to a larger pore volume than before the treatment.

Case Study 2: Well 5 (Bench Y, ESP)

Well 5 was chosen as a proactive ESP downsize candidate, following the same steps performed on Well 1. During the injection, the well communicated with an offset but experienced no issues or positive uplift from the injection. The well came online after 9 days, initially producing high water volumes before returning to baseline oil rates within 3 days. The installed ESP had erratic performance and failed after 3 months. A new ESP was installed, which maintained stable performance for a year. FIG. 29 shows the oil baseline and post-treatment response for the well, noting the early ESP failure after initial treatment. The change in ESP did not alter the improvement in decline response for the well, highlighting another treatment success for the designed surfactant: the improvements gained will still hold through artificial lift challenges.

The effects of artificial lift changes were isolated and confirm this improvement mechanism by exploring the RTA and MFMB response for Well 5, as seen in FIG. 30A-30B. The PI improvement response visually is sustained through the artificial lift change. The pressure-normalized oil rate (PI) improvement response visually sustained through the artificial lift change. Analytically, a 47% increase in LFP gained by the surfactant treatment was observed. The same improvements were confirmed visually with a shallower slope response for MFMB and analytically with an 80% increase in contacted pore volume (OOIP). The results show that if the well's VFP is managed correctly, the return on the surfactant treatment is maximized.

Case Study 3: Well 7 (Bench Z, Gas Lift)

Well 7 was selected as a candidate to trial treatments on wells with gas lift completions. Limited to the conventional gas lift valves installed on Well 7, operations ensured that post treatment was optimized as best as possible. After finalizing pre-work and job design, a rig-less treatment was executed on the well followed by a 21-day soak period. RTP saw high initial water rates followed by a return to baseline oil response within 29 days, as seen in FIG. 31. The post-treatment response was held but returned to baseline after a year.

The benefits of the treatment were further confirmed via RTA and MFMB (FIG. 32A-32B), noting visual and analytical improvements of 2% LFP and 56% contacted pore volume (OOIP) increase, respectively. Although Well 7's uplift response is muted compared to its ESP peers treated within the same timeframe and limited by fixed gas lift design, improvement in production through multiple signposts was confirmed. The results show that the surfactant treatments can still improve rock-fluid and fluid-fluid subsurface interactions even with limiting VFP.

CONCLUSIONS

This work explored results associated with piloting the use of surfactants to enhance oil recovery and improved well performance in unconventional assets. An extensive laboratory workflow was used to overcome the challenge of developing a robust surfactant formulation capable of altering wettability and lowering IFT to mobilize oil. An extensive execution workflow was developed to minimize production downtime while maximizing learning opportunities. initial challenges were quickly transformed into opportunities to refine execution strategies. Stimulation with the correct design and implementation of surfactant additives can improve oil recovery, maximizing well performance after stimulation. In terms of candidate selection, depletion and vertical flow performance play an important role in treatment design.

For treatment design, treatment timing as a proxy for depletion and spacing are critical factors. Understanding a surfactant's dosage limits is critical to preventing operational setbacks. If a surfactant package is designed correctly, extended shut-in and soak time will not negatively impact production response. Alternatively, extended soak times seem to not be necessary.

Effective communication plans, baseline surveys of wells and supporting facilities, flow assurance management for surfactant packages, and risk assessments are advocated to effectively pilot chemical EOR in unconventional liquid reservoirs.

NOMENCLATURE

• • Bbl/d=Barrels per day
  • bpm=Rate, barrels per minute
  • BS&W=Base sediment & water
  • BW/ft=Barrels ofwater per foot
  • CTB=Central tank battery
  • GL=Gas lift
  • gpt=Gallons per thousand gallons
  • ESP=Electrical submersible pump
  • IFT=Interfacial tension, dynes/cm or mN/m
  • IPR=Inflow performance
  • LFP=Linear flow parameter, or A k
  • MFMB=Multiphase flowing material balance
  • Mbbls=Thousand Barrels
  • PI=Productivity index
  • md=Millidarcy
  • mN/m=Millinewton per meter
  • QA/QC=Quality assurance/quality control
  • RTA=Rate transient analysis
  • RTP=Return to production
  • SWD=Saltwater Disposal Facility
  • TDS=Total dissolved solids, ppm or mg/L
  • VFP=Vertical flow performance
  • wt %=Weight percent

The description and illustration of one or more embodiments provided in this application are not intended to limit or restrict the scope of the invention as claimed in any way. The embodiments, examples, and details provided in this disclosure are considered sufficient to convey possession and enable others to make and use the best mode of the claimed invention. The claimed invention should not be construed as being limited to any embodiment, example, or detail provided in this application. Regardless of whether shown and described in combination or separately, the various features (both structural and methodological) are intended to be selectively included or omitted to produce an embodiment with a particular set of features. Having been provided with the description and illustration of the present application, one skilled in the art may envision variations, modifications, and alternate embodiments falling within the spirit of the broader aspects of the claimed invention and the general inventive concept embodied in this application that do not depart from the broader scope. For instance, such other examples are intended to be within the scope of the claims if they have structural or methodological elements that do not differ from the literal language of the claims, or if they include equivalent structural or methodological elements with insubstantial differences from the literal language of the claims, etc. All citations referred to herein are expressly incorporated by reference.