METHODS OF TREATING A SUBTERRANEAN FORMATION CONTAINING HYDROCARBONS

Abstract

A method of treating a subterranean formation containing hydrocarbons is disclosed, the method comprising: modifying the subterranean formation with a surface energy reducing agent; and injecting into the subterranean formation a fracturing fluid containing a base fluid and a gelling agent; in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit under 35 U.S.C. §119(e) of Provisional Application No. 61/433,076, filed Jan. 14, 2012.

TECHNICAL FIELD

This document relates to methods of treating a subterranean formation containing hydrocarbons.

BACKGROUND

In the conventional fracturing of wells, producing formations, new wells or low producing wells that have been taken out of production, a formation can be fractured to attempt to achieve higher production rates. Proppant and fracturing fluid are pumped into a well that penetrates an oil or gas bearing formation. High pressure is applied to the well, the formation fractures and proppant carried by the fracturing fluid flows into the fractures. The proppant in the fractures holds the fractures open after the pressure is relaxed and production is resumed. Various fluids have been disclosed for use as the fracturing fluid, including liquefied petroleum gas (LPG). Various chemicals may be added to the fracturing fluid, such as gelling agents, breakers, activators, and surfactants.

SUMMARY

A method of treating a subterranean formation containing hydrocarbons is disclosed, the method comprising: modifying the subterranean formation with a surface energy reducing agent; and injecting into the subterranean formation a fracturing fluid containing a base fluid and a gelling agent; in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent.

In various embodiments, there may be included any one or more of the following features: The surface energy reducing agent is selected such that the modified subterranean formation does not bond with the gelling agent. The surface energy reducing agent adheres to the subterranean formation more strongly than the gelling agent adheres to the subterranean formation. The surface energy reducing agent is selected to effectively reduce the net force of adhesion between the subterranean formation and the gelling agent (F_FG) from above to below the net force of cohesion of the gelling agent (F_GG). The method comprises breaking a gel, formed of the gelling agent, in the subterranean formation, in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent when broken. Modifying is carried out by injecting fracturing fluid comprising the surface energy reducing agent. Modifying comprises coating. The surface energy reducing agent comprises a surfactant. The surfactant comprises one or more of an ionic surfactant and a non-ionic surfactant. The ionic surfactant comprises one or more of an anionic surfactant, a cationic surfactant, and a zwitterionic surfactant. The surface energy reducing agent comprises an alkyne-diol. The surface energy reducing agent comprises one or more of Surfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604, and Dynol 607. The base fluid comprises hydrocarbons and the gelling agent comprises a gelling agent for hydrocarbons. The gelling agent comprises a polyacrylimide. The gelling agent comprises a phosphate. The base fluid comprises liquefied petroleum gas. The gelling agent comprises a gelling agent for liquefied petroleum gas. The gelling agent is selected to have a surface tension of between twenty and forty-six dynes/cm when in the subterranean formation after breaking.

These and other aspects of the device and method are set out in the claims, which are incorporated here by reference.

BRIEF DESCRIPTION OF THE FIGURES

Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which:

FIG. 1A is side elevation view of an apparatus for treating a subterranean formation.

FIG. 1B is a flow diagram of a method of treating a subterranean formation containing hydrocarbons.

FIG. 2A is an exploded view that illustrates a gelling agent adhering to an untreated formation.

FIG. 2B is an exploded view that illustrates the reduced adherence of gelling agent to the formation of FIG. 2A after coating, for example adsorbing, the formation with surface energy reducing agent.

FIGS. 3A-F are photographs of a formation test surface coated with no surfactant, Surfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604, and Dynol 607, respectively, immersed in gelled pentane, and spotted with accudyne pens of varying surface tensions.

DETAILED DESCRIPTION

Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims.

During well treatment, gelling agents or other injected chemicals may stick to the formation on flowback, reducing permeability and potentially plugging the well. Surface science has identified at least five mechanisms of adhesion to explain why one material sticks to another, namely mechanical adhesion, electrostatic adhesion, chemical adhesion, dispersive adhesion, and diffusive adhesion. Regarding the adherence of a liquid to a solid or coated solid in a downhole environment, the latter three appear most relevant. Chemical adhesion occurs when two materials form a compound at the join. Ionic, covalent, and hydrogen bonding are examples of chemical adhesion. Diffusive adhesion occurs when materials merge at the joint by diffusion, for example if the molecules of the liquid are mobile and soluble in the solid or liquid coating the solid. Dispersive adhesion, similar to chemical adhesion, occurs when two materials are held together by van der Waals forces, which involve the attraction between slightly charged molecules, such as polar compounds. Positive and negative poles may be a permanent property of a molecule (Keesom forces) or a transient effect which can occur in any molecule (London forces).

In surface science, adhesion usually refers to dispersive adhesion. In a solid-liquid-gas system (such as a drop of liquid on a solid surrounded by air) contact angle may quantify adhesiveness. In general, where the contact angle 45 is low (ex. FIG. 2A) more adhesion is present than when the contact angle 45 is large (ex. FIG. 2B). The amount of adhesion is related to the difference between the surface energy of the surface and the surface tension of the liquid. Surface energy is the excess energy at the surface of a material compared with the material as a whole. Surface tension refers to the surface energy of a liquid. Regardless, the contact angle of a three-phase system is a function not only of dispersive adhesion between the molecules in the liquid and the molecules in the solid, but also cohesion, which is dispersive interaction between like liquid molecules. Strong adhesion and weak cohesion may result in a high degree of wetting (ex. FIG. 2A), which may be a lyophilic condition with low measured contact angles. Conversely, weak adhesion and strong cohesion may result in lyophobic conditions with high measured contact angles and poor wetting (FIG. 2B). Table 1 below illustrates surface energies from some example materials.

TABLE 1
Example Surface Energies
                          SURFACE ENERGY/TENSION
SURFACE                   (Dynes/cm)
Copper                    1,103
Sand                      1000
Aluminum                  840
Water                     72
Broken Polyacrylimide Gel 35
Hydrocarbons              20-30
Propane                   <20
Teflon (DuPont)           18

Referring to FIG. 1A, a system 11 for treating a subterranean formation 24 containing hydrocarbons is illustrated. Subterranean formation 24 is a hydrocarbon reservoir, which may be treated for example by injection through a well 22 penetrating the hydrocarbon reservoir 24. Fracturing fluid base fluid may be initially contained within a storage tank 10. Tank 10 may comprise a tanker truck or a large vessel.

A generic example treatment of subterranean formation 24 goes as follows. The fracturing fluid may be pumped from reservoir 10 down line 12, where various components may be added to the fluid, for example via one or more component addition systems 14, 16, 18. For example, components such as gelling agent and proppant may be added from addition systems 16 and 18, respectively. The addition systems may be, for example, hoppers. Once the fracturing fluid is prepared and ready, a frac pressure pump 20 injects the frac fluid down a well 22 and into subterranean formation 24. In some cases, one or more component or fluid may be added to the frac fluid after the pump 20. The concept of reservoir treatment is well known, and the details need not be described here. In fracturing treatments, pressure may be applied to the frac fluid injected into the subterranean formation 24. The pressure may be sufficient to cause fracturing of the subterranean formation.

Referring to FIG. 1B, a method of treating subterranean formation 24 is illustrated. The method will now be described with reference to the other Figures. Referring to FIG. 1A, in a stage 40, the subterranean formation 24 is modified with a surface energy reducing agent, for example from addition system 18. Modifying may be carried out by injecting fracturing fluid comprising the surface energy reducing agent. For example, a pad of base fluid from tank 10 may be combined with surface energy reducing agent from addition unit 18, and pumped via frac pressure pump 20 down well 22. However, the surface energy reducing agent may also be injected neat or with another suitable fluid. As the surface energy reducing agent contacts the subterranean formation, the surface energy reducing agent may coat the formation (FIG. 2B) and effectively reducing the surface energy of the formation. In some embodiments substantially the entire surface area of the subterranean formation that will come into contact with the fracturing fluid is coated. In some cases, the surface energy reducing agent is supplied throughout the entire injection of frac fluid. In some embodiments, the proppant used, such as sand, may be pre-coated or co-injected with surface energy reducing agent. Coating a surface reduces roughness of the coated surface and thus is beneficial as adherence may increase with greater degrees of roughness.

In a stage 42, a fracturing fluid containing a base fluid, for example from tank 10, and a gelling agent, for example from addition unit 16, is injected into the subterranean formation 24. The treatment, which may be a fracturing treatment, may then be completed, for example by pressuring up the fluid in well 22 to frac, and delivering proppant from addition unit 16 into the fractures formed in the subterranean formation.

Referring to FIGS. 2A and 2B, the effect of the surface energy reducing agent 44 will now be described. FIG. 2A illustrates a situation where the injected gelling agent 46 has a surface tension that is lower than the surface energy of the formation 24. As is shown, a contact angle 45 less than 90 degrees indicates high adherence. In most formations, for example sandstone formations, the surface energy of the formation 24 will be larger than the surface tension of the gelling agent 46, effectively causing gelling agent 46 to wet and adhere to the formation 24. FIG. 2B illustrates the beneficial effect of the surface energy reducing agent 44, which has been selected to effectively reduce the surface energy of the formation 24 to at or below the surface tension of the gelling agent 46. In FIG. 2B, the contact angle 45 is greater than 90 degrees, indicating a low degree of wetting, and likely a low degree of adherence. Thus, for a polymer gel such as polyacrylamide gel with a surface tension of 35, the surface energy reducing agent 44 must reduce the surface energy to thirty-five dynes/cm or lower, for example down to twenty dynes/cm. In most cases, the desired result will be achieved if the surface energy reducing agent 44 is selected to reduce the net force of adhesion between the subterranean formation 24 and the gelling agent (F_FG) from above to below the net force of cohesion of the gelling agent (F_GG).

The surface energy reducing agent 44 may be selected such that the modified subterranean formation shown in FIG. 2B does not bond, for example chemically, with the gelling agent 46. For example, the surface energy reducing agent 44 may be selected to form a hydrophobic coating if the gelling agent 46 is known to be hydrophilic. Thus, when the frac pressure is reduced and flowback induced, gelling agent 46 is able to slide off of formation 24 and be removed from the well 22. The surface energy reducing agent 44 may also be selected to adhere to the subterranean formation 24 more strongly than the gelling agent 46 adheres to the subterranean formation 24. Thus, diffusion of the gelling agent 46 into the thin film coating formed by the surface energy reducing agent 46 does not result in gelling agent 46 displacing surface energy reducing agent 44 and adhering to the formation 24. However, in some cases this is not required, and a thin low adherence film of surface energy reducing agent may be sufficient to allow substantial removal of gelling agent and related chemicals from the well 22.

The gelling agent 46 selected may have a surface tension of between twenty and forty-six dynes/cm when in the subterranean formation after breaking. In some cases the method includes the stage of breaking a gel, formed of the gelling agent 46, in the subterranean formation 24, in which the surface energy reducing agent 44 is selected to effectively reduce the surface energy of the subterranean formation 24 to at or below the surface tension of the gelling agent 46 when broken. Thus, the broken gelling agent is targeted by the surface energy reducing agent 44, as it is broken gel that may be left in formation 24. This may be a consideration if the gelling agent changes surface tension upon breaking due to a chemical change in the gelling agent. The surface energy reducing agent may make the formation 24 omniphobic, in order to allow easy removal of the base fluid as well as the fracturing chemicals.

Referring to FIGS. 3A-F, the surface energy reducing agent may comprise a surfactant, such as an alkyne-diol. Accudyne testing was carried out on a formation 24 sample immersed in pentane gelled with 16 L/m³ gel, 16 L/m³ activator, and 8 L/m³ breaker. The formation sample tested was a shale sample from Alberta. In this test, a surface energy reducing agent was introduced and coated on formation 24 sample. Afterwards, accudyne pens of different surface tensions were spotted on the formation 24 sample, in order to determine if surface energy had been reduced. In general, a solid spot produced by a pen with a surface tension X indicates that the formation has a surface energy above X, while a splotchy or beaded spot produced by the same pen indicates low adherence due to the fact that the formation has a surface energy at or below X. For ease of illustration, reference numerals 54, 56, 58, 60, 62, and 64 identify spots made by accudyne pens of surface tensions 30, 32, 34, 36, 38, and 40 dynes/cm, respectively. FIG. 3A was used as a blank formation sample 24, with no surface energy reducing agent added to the gelled pentane. In FIGS. 3B-F, the surface energy reducing agent comprises Surfanol MB (FIG. 3B), Surfanol 104-PG50 (FIG. 3C), Surfanol 2502 (FIG. 3D), Dynol 604 (FIG. 3E), and Dynol 607 (FIG. 3F). In FIG. 3A where no surface energy reducing agent was used, accudyne pens having surface tensions 34 dynes/cm and 36 dynes/cm were able to clearly form solid spots 58 and 60, respectively, indicating that the surface energy of formation sample 24 was at least greater than 36 dynes/cm and likely much higher. By contrast, the surfactants used in FIGS. 3B-F all effectively reduced the surface energy of formation 24 sample, as evidenced by the beaded spots left by most of the pens. The following Table 2 indicates the estimated effective surface energy of the modified formation 24 samples based on the tesing.

TABLE 2
Accudyne Test Results
			Effective Surface Energy of
	Fig.	Surfactant added	Modified Formation 24 Sample
	3A	none	>36 (likely much higher)
	3B	Surfanol MB	<30
	3C	Surfanol 104-PG50	<30
	3D	Surfanol 2502	34-36
	3E	Dynol 604	32-34
	3F	Dynol 607	<30

The base fluid may comprise hydrocarbons, such as C₆-C₂₀ hydrocarbons, and the gelling agent may comprise a gelling agent for hydrocarbons. The gelling agent may comprise a phosphate based chemical. In other cases the base fluid may be water, and the gelling agent may be a gelling agent for water. The base fluid may comprise liquefied petroleum gas, and the gelling agent may comprise a gelling agent for liquefied petroleum gas. LPG has been advantageously used as a fracturing fluid to simplify the recovery and clean-up of frac fluids after a frac. Exemplary LPG frac systems are disclosed in WO2007098606, incorporated herein by reference. One example of a suitable gelling agent for LPG is created by first reacting diphosphorous pentoxide with triethyl phosphate and an alcohol having hydrocarbon chains of 3-7 carbons long, or in a further for example alcohols having hydrocarbon chains 4-6 carbons long. The orthophosphate acid ester formed is then reacted with aluminum sulphate to create the desired gelling agent. The gelling agent created will have hydrocarbon chains from 3-7 carbons long or, as in the further example, 4-6 carbons long. The hydrocarbon chains of the gelling agent are thus commensurate in length with the hydrocarbon chains of liquid petroleum gas used for the frac fluid. This gelling agent is more effective at gelling a propane or butane fluid than a gelling agent with longer hydrocarbon chains. The proportion of gelling agent in the frac fluid is adjusted to obtain a suitable viscosity in the gelled frac fluid.

In some embodiments, a volatile-phosphorus free gelling agent may be used, for example for gelling hydrocarbons. Such a gelling agent may have the general formula of:

where X is an OR¹, NR¹R², or SR¹ group, R¹ is an organic group having 2-24 carbon atoms, and R² is an organic group or a hydrogen. Y is an NR³R⁴ or SR³ group, R³ is an organic group having 2-24 carbon atoms, and R⁴ is an organic group or a hydrogen. Such gelling agent may be made as follows. Phosphorus oxyhalide is reacted with a chemical reagent to produce substantially only diester phosphorus oxyhalide, the chemical reagent comprising at least one of an organic alcohol having 2-24 carbon atoms, an organic amine with an organic group having 2-24 carbon atoms, and an organic sulfide having 2-24 carbon atoms. The diester phosphorus oxyhalide is then hydrolyzed to produce diester phosphoric acid. Further examples are given in WO/2010/022496, incorporated herein by reference.

LPG may include a variety of petroleum and natural gases existing in a liquid state at ambient temperatures and moderate pressures. In some cases, LPG refers to a mixture of such fluids. These mixes are generally more affordable and easier to obtain than any one individual LPG, since they are hard to separate and purify individually. Unlike conventional hydrocarbon based fracturing fluids, common LPGs are tightly fractionated products resulting in a high degree of purity and very predictable performance. Exemplary LPGs include ethane, propane, butane, or various mixtures thereof. As well, exemplary LPGs also include isomers of propane and butane, such as iso-butane. Further LPG examples include HD-5 propane, commercial butane, and n-butane. The LPG mixture may be controlled to gain the desired hydraulic fracturing and clean-up performance. LPG fluids used may also include minor amounts of pentane (such as i-pentane or n-pentane), and higher weight hydrocarbons.

LPGs tend to produce excellent fracturing fluids. LPG is readily available, cost effective and is easily and safely handled on surface as a liquid under moderate pressure. LPG is completely compatible with formations and formation fluids, is highly soluble in formation hydrocarbons and eliminates phase trapping—resulting in increased well production. LPG may be readily and predictably viscosified to generate a fluid capable of efficient fracture creation and excellent proppant transport. After fracturing, LPG may be recovered very rapidly, allowing savings on clean up costs. In some embodiments, LPG may be predominantly propane, butane, or a mixture of propane and butane. In some embodiments, LPG may comprise more than 80%, 90%, or 95% propane, butane, or a mixture of propane and butane.

Exemplary gelling agents that may be used are disclosed by Whitney in U.S. Pat. Nos. 3,775,069 and 3,846,310, the specifications of which are incorporated by reference. Such gelling agents may create water-sensitive gels. An example of a suitable gelling agent comprises a combination of an alkoxide of a group IIIA element and an alkoxide of an alkali metal. When combined, the alkoxide of the group IIIA element and the alkoxide of the alkali metal react to form a polymer gel. The group IIIA element may comprise one or more of boron and aluminum for example. In some embodiments, the alkoxide of a group IIIA element comprises M¹(OR¹)(OR²)(OR³), in which M¹=the group IIIA element, and R¹, R², and R³ are organic groups. Each of the organic groups of R¹, R², and R³ may have 2-10 carbon atoms, and may comprise an alkyl group. In one embodiment, M¹=boron, and R¹, R², and R³ comprise 2-10 carbon atoms. The alkali metal may comprise one or more of lithium, sodium, and potassium for example. In some embodiments, the alkoxide of an alkali metal further comprises M²(OR⁴), in which M²=the alkali metal, and R⁴ comprises an organic group. The organic group of R⁴ may comprise 2-24 carbon atoms, for further example 12 carbon atoms, and may comprise an alkyl group. In one embodiment, M²=lithium and the organic group of R⁴ comprises 2-24 carbon atoms. In some embodiments, R⁴ may further comprise: (AQ)_n(R⁵)_x(R⁶)_y. in which A is an organic group, Q is O or N, n is 1-10, R⁵ and R⁶ are organic groups, x is either 1 or 2 depending on the valence of Q, and y is 0 or 1 depending on the valence of Q. Thus, the alkoxide of an alkali metal formed would have the formula of M²O(AQ)_n(R⁵)_x(R)_y. A may have 2-4 carbon atoms. The organic groups of R⁵ and R⁶ may each have 1-16 carbons. Where y=1, R⁶ is bonded to the Q atom. Organic groups as disclosed herein may refer to groups with at least one carbon atom, as long the resulting gelling agent is suitable for its purpose. Examples of organic groups include phenyl, aryl, alkenyl, alkynyl, cyclo, and ether groups. A suitable amount of gelling agent may be used, for example 0.25-5% by weight of the fracturing fluid. In addition, the a suitable ration of the alkoxide of a group IIIA element and the alkoxide of an alkali metal may be used, for example 3:1 to 1:3, with 1:1 being a preferable ratio.

The following exemplary procedure may be used to form a fracturing fluid containing a water sensitive gel as discussed in the preceding paragraph. Butyl lithium (3.53 mL of a 1.7 M solution in pentane, 6 mmol) was added dropwise to a stirring solution of dodecanol (1.12 g, 6 mmol) in pentane (125.00 g, 1% by wt gelling agents in pentane). This mixture was then stirred for a further 1 h at room temperature. A separate solution of tributyl borate (1.62 mL, 6 mmol) in pentane (125.00 g) was prepared in a blender at 17% variance with a rheostat for 5 min. To this solution was added the lithium alkoxide solution and a hydrated breaker, for example CaSO₄(2H₂O) (2.91 g, 0.15% by vol. H2O, 60 mesh) Blending was continued for 1 min at 30% variance. Over this time cloudy white gels formed. These were tested on a Brookfield viscometer-60° C., 4 h, 110 psi.

Exemplary breakers for use with water-sensitive gels include hydrated breakers. For example, the hydrated breaker may comprise one or more hydrates, wherein water of the one or more hydrates is releasable so as to act with the water-sensitive carrier to reduce the viscosity of the fracturing fluid. A hydrated breaker may have a crystalline framework containing water that is bound within the crystalline framework and releasable into the fracturing fluid to act on the water-sensitive gel to reduce the viscosity of the fracturing fluid. Hydrated breakers are disclosed for example in U.S. application Ser. No. 12/609,893 and CA Application No. 2685298 the content of which is incorporated here by reference where permitted by law.

In some embodiments, a gelling agent need not be specifically targeted by the surface energy reducing agent. For example, the surface energy reducing agent may be selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of one or more of the base fluid, breaker, activator, gelling agent, or other treating chemical. Thus, the targeted injected chemicals may be easily removed after treatment is complete, and potential for well damage by tacky chemicals is reduced or eliminated.

Various surfactants may be used as the surface energy reducing agent. For example, the surfactant may comprise one or more of an ionic surfactant and a non-ionic surfactant. For further example, if used the ionic surfactant may comprise one or more of an anionic surfactant, a cationic surfactant, and a zwitterionic surfactant.

Anionic surfactants may be based on permanent anions such as sulfate, sulfonate, and phosphate, or pH-dependent anions such as carboxylate. Example anionic surfactants based on sulfates include alkyl sulfates such as ammonium lauryl sulfate and sodium lauryl sulfate (SDS), alkyl ether sulfates such as sodium laureth sulfate (also known as sodium lauryl ether sulfate or SLES), and sodium myreth sulfate. Example anionic surfactants based on sulfonates include docusates such as dioctyl sodium sulfosuccinate. Example anionic surfactants based on sulfonates also include sulfonate fluorosurfactants such as perfluorooctanesulfonate (PFOS), and perfluorobutanesulfonate. Example anionic surfactants based on sulfonates also include alkyl benzene sulfonates. Example anionic surfactants based on phosphates include alkyl aryl ether phosphate and alkyl ether phosphate. Example anionic surfactants based on carboxylates include alkyl carboxylates such as fatty acid salts (soaps) and sodium stearate. Example anionic surfactants based on carboxylates also include sodium lauroyl sarcosinate. Example anionic surfactants based on carboxylates also include carboxylate fluorosurfactants such as perfluorononanoate, and perfluorooctanoate (PFOA or PFO).

Cationic surfactants may be based on pH-dependent amines or permanently charged quaternary ammonium cations. Example cationic surfactants based on pH-dependent amines include primary, secondary or tertiary amines. For example, primary amines may be used that become positively charged at pH<10, and secondary amines may be used that become charged at pH<4. One example of a pH-dependent amine is octenidine dihydrochloride. Example cationic surfactants based on permanently charged quaternary ammonium cations include alkyltrimethylammonium salts such as cetyl trimethylammonium bromide (CTAB a.k.a. hexadecyl trimethyl ammonium bromide), and cetyl trimethylammonium chloride (CTAC). Example cationic surfactants based on permanently charged quaternary ammonium cations also include cetylpyridinium chloride (CPC), polyethoxylated tallow amine (POEA), benzalkonium chloride (BAC), benzethonium chloride (BZT), 5-bromo-5-nitro-1,3-dioxane, dimethyldioctadecylammonium chloride, and dioctadecyldimethylammonium bromide (DODAB).

Zwitterionic surfactants, which may be amphoteric, may be based on primary, secondary or tertiary amines or quaternary ammonium cations with sulfonate, carboxylate, or phosphate anions. Example zwitterionic surfactants with sulfonates include CHAPS (3-[(3-Cholamidopropyl)dimethylammonio]-1-propanesulfonate), and sultaines such as cocamidopropyl hydroxysultaine. Example zwitterionic surfactants with carboxylates include amino acids, imino acids, and betaines such as cocamidopropyl betaine. Example zwitterionic surfactants with phosphates include lecithin.

Nonionic surfactants may include fatty alcohols such as cetyl alcohol, stearyl alcohol, cetostearyl alcohol (for example comprising predominantly of cetyl and stearyl alcohols), and oleyl alcohol. Nonionic surfactants may also include polyoxyethylene glycol alkyl ethers (Brij or CH₃—(CH₂)_10-16—(O—C₂H₄)_1-25—OH) such as octaethylene glycol monododecyl ether, and pentaethylene glycol monododecyl ether. Nonionic surfactants may also include polyoxypropylene glycol alkyl ethers (CH₃—(CH₂)_10-16—(O—C₃H₆)_1-25—OH). Nonionic surfactants may also include glucoside alkyl ethers (CH₃—(CH₂)_10-16—(O-Glucoside)_1-3-OH) such as decyl glucoside, lauryl glucoside, and octyl glucoside. Nonionic surfactants may also include polyoxyethylene glycol octylphenol ethers (C₈H₁₇—(C₆H₄)—(O—C₂H₄)_1-25—OH) such as Triton X-100. Nonionic surfactants may also include polyoxyethylene glycol alkylphenol ethers (C₉H₁₉—(C₆H₄)—(O—C₂H₄)_1-25—OH) such as nonoxynol-9. Nonionic surfactants may also include glycerol alkyl esters such as glyceryl laurate. Nonionic surfactants may also include polyoxyethylene glycol sorbitan alkyl esters such as polysorbates. Nonionic surfactants may also include sorbitan alkyl esters such as spans. Nonionic surfactants may also include cocamide MEA, and cocamide DEA. Nonionic surfactants may also include dodecyl dimethylamine oxide, and block copolymers of polyethylene glycol and polypropylene glycol such as poloxamers.

TABLE 3
Accudyne Test Results on non-ionic, anionic, and
cationic surfactants in gelled LPG (LP10).
                                 Effective Surface Energy of
Surfactant added                 Modified Formation 24 Sample
1-hexadecanol (non-ionic)        34-36
Sodium dodecyl sulfate (anionic) 32-34
Benzalkonium Chloride (cationic) 38-40

LP10 is a broken dialkyl phosphate LPG gel.

In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.

Claims

1. A method of treating a subterranean formation containing hydrocarbons, the method comprising:

modifying the subterranean formation with a surface energy reducing agent; and

injecting into the subterranean formation a fracturing fluid containing a base fluid and a gelling agent;

in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent.

2. The method of claim 1 in which the surface energy reducing agent is selected such that the modified subterranean formation does not bond with the gelling agent.

3. The method of claim 1 in which the surface energy reducing agent adheres to the subterranean formation more strongly than the gelling agent adheres to the subterranean formation.

4. The method of claim 1 in which the surface energy reducing agent is selected to effectively reduce the net force of adhesion between the subterranean formation and the gelling agent (FFG) from above to below the net force of cohesion of the gelling agent (FGG).

5. The method of claim 1 further comprising breaking a gel, formed of the gelling agent, in the subterranean formation, in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent when broken.

6. The method of claim 1 in which modifying is carried out by injecting fracturing fluid comprising the surface energy reducing agent.

7. The method of claim 1 in which modifying comprises coating.

8. The method of claim 1 in which the surface energy reducing agent comprises a surfactant.

9. The method of claim 8 in which the surface energy reducing agent comprises an alkyne-diol.

10. The method of claim 8 in which the surface energy reducing agent comprises one or more of Surfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604, and Dynol 607.

11. The method of claim 8 in which the surfactant comprises one or more of an ionic surfactant and a non-ionic surfactant.

12. The method of claim 11 in which the ionic surfactant comprises one or more of an anionic surfactant, a cationic surfactant, and a zwitterionic surfactant.

13. The method of claim 1 in which the base fluid comprises hydrocarbons and the gelling agent comprises a gelling agent for hydrocarbons.

14. The method of claim 13 in which the gelling agent comprises a polyacrylimide.

15. The method of claim 1 in which the base fluid comprises liquefied petroleum gas.

16. The method of claim 15 in which the gelling agent comprises a gelling agent for liquefied petroleum gas.

17. The method of claim 1 in which the gelling agent is selected to have a surface tension of between twenty and forty-six dynes/cm when in the subterranean formation after breaking.