Compositions and Methods for Treating Unconventional Subterranean Formations

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.

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.

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 Rcomprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking Rand R; Rcomprises 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 Rcomprises 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 Ris 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 Rcomprises a branched or unbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms and an oxygen atom linking Rand R; Rcomprises 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 Rcomprises 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 Ris 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.

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.

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.

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.

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.