Solid incorporated reversible emulsion for a fracturing fluid

Abstract

Embodiments of this invention relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a degradable material, introducing the fluid into a wellbore, and allowing the degradable material to degrade. Embodiments of this invention relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a fluid loss additive, introducing the fluid into a wellbore, and allowing the fluid loss additive to degrade.

Description

BACKGROUND

1. Field

This invention relates to fluids for use in the oil field services industry. In particular, the invention relates to methods and compositions including degradable particles in an emulsion.

2. Description of the Related Art

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Conventionally, hydraulic fracturing processes use a polymeric fluid during the PAD stage of fracturing, followed by proppant placement in the fracture using a polymeric water based carrier fluid. During such process the polymeric water based fluid dehydrates and fluid loss occurs under a differential pressure into the fractured formation. The dehydration process builds a filtercake on the fractured surface and it contains a high concentration of polymer compared with the initial bulk fluid. The controlled filtercake thickness increases with time and the amount of fluid lost into the fractured formation. The filtercake may build to the extent that it fills the entire fracture width thus impairing the flow of formation fluids due to the high yield stress of the concentrated polymer filter cake. The breaking of the polymers that both invade the formation and reside within the fracture is desired to improve flow of formation fluids both from the formation to the fracture and through the fracture into the wellbore. In water sensitive formations preference is given to oil based fracturing fluid.

An improved composition is needed to decrease fluid loss into the fractured formation, minimize the thickness of the filtercake, reduce damage to the formation, enhance fracture conductivity, increase fracture length, improve cleanup of the filtercake and enhance production of hydrocarbons. Direct application of a degradable acid generating, solid particulate additive for emulsion reversal from water-in-oil to oil-in-water, fluid loss control, altering wettability from oil wet to water wet, generating acid in-situ and enhancing fracturing conductivity either in drilling or fracturing applications is needed.

SUMMARY

Some embodiments relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid containing a reverse emulsion and a degradable material, introducing the fluid into a wellbore, and allowing the degradable material to degrade.

Some other embodiments relate to an apparatus and a method for treating a subterranean formation permeated by a wellbore including forming a fluid comprising a reverse emulsion and a fluid loss additive, introducing the fluid into a wellbore, and allowing the fluid loss additive to degrade.

BRIEF DESCRIPTION OF THE FIGURES

For further understanding of some embodiments, and the advantages thereof, reference is now made to the following description taken in conjunction with the accompanying figures, in which:

FIG. 1 is a schematic figure illustrating the behavior of a reversible emulsion.

FIG. 2 is a schematic figure illustrating a filtercake with particulate additive and trapped water droplets that reverses with time through hydrolysis of the particulates.

FIG. 3 is a plot of viscosity and temperature as a function of time for a fluid comprising 2 weight percent PGA compared to a baseline of an embodiment of the invention.

FIG. 4 is a plot of viscosity and temperature as a function of time for a fluid comprising 3 weight percent PGA compared to a baseline of an embodiment of the invention.

FIG. 5 is a plot of fluid loss as a function of time comparing an emulsion and 3 weight percent PGA fluid for an embodiment of the invention.

FIG. 6 is a plot of electrical stability as a function of volume of citric acid for an embodiment of the invention.

DESCRIPTION

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. The description and examples are presented solely for the purpose of illustrating the preferred embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. While the compositions of the present invention are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already cited.

In the summary of the invention and this description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10.Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors have disclosed and enabled the entire range and all points within the range.

Embodiments of this invention prevent high fluid loss from a conventional water based fracturing fluid which often results in a thick and highly concentrated polymer filtercake on the fracture surface and high formation damage, reduced fracture conductivity, reduced fracture length and low production rate across the fracture and fracture surface. In addition, embodiments of the invention address the cleanup of the concentrated polymer filtercake on the fractured surface and within the fracture for improved conductivity.

Traditionally, fluid loss reduction has relied on a combination of polymers and solid particulates. In water sensitive formations, preference is given to oil based fluids. Both an emulsion and solid particulates can be used together. The emulsion is specifically designed to be reversible and to reduce fluid loss. The water-in-oil emulsion is reversed to oil-in-water and vice versa by reducing or increasing the pH respectively. This reversible feature allows better cleanup of the emulsion cake that is formed on the subterranean wall or the fracture surface. Often, an emulsion lowers the fluid loss compared to water based drilling fluids. The solid particulates are used as bridging agents and as fluid loss agents initially. Subsequently, the solids degrade and generate acid upon hydrolysis. The multi-functionality features of the additives include control of fluid loss, generation of acid in situ, self-degradation, cleaning the filtercake, and improving fracture conductivity. In addition, the concept uses a degradable material that initially helps to control fluid loss and subsequently degrades resulting in an improved conductivity.

An effective fluid contains a reversible emulsion and an acid generating, degradable solid particulate additive. The reversible emulsion of water-in-oil contains an amphoteric surfactant that allows reversing of the emulsion to oil-in-water when the pH is reduced towards the acid range. The pH reduction is obtained by the particulate additives that generate acid upon hydrolysis with temperature. In addition, the solid particulate additive acts as bridging agent initially and helps to control the fluid loss into the formation. Subsequently, with time and temperature, the particulates hydrolyze and generate acid that reverses the emulsion. The reversed emulsion helps alter the wettability of the formation from oil wet to water wet thus enhancing the productivity. It also helps in the cleanup of the emulsion filtercake and improves the fracture conductivity.

The fluid loss is controlled by the solid particulates that are degradable and may comprise of poly glycolic acid (PGA), poly vinyl acetate (PVAc), poly lactic acid (PLA), or its copolymer, or its different degree of hydrolysis or its mixture added to a conventional fracturing fluid. The particulates may be of different molecular weight, size distribution, shape, and concentration selected to control fluid loss, cake compressibility, and/or the rate of hydrolysis. The rate of hydrolysis may also be controlled by coating the particles. In some embodiments, liquid acids may be selected that are encapsulated. For example, encapsulated fumaric acid may be used in some embodiments. When encapsulated, the acids, any suitable encapsulation material or method may be used. In some instances, the acid is encapsulated with oil, which may affect acid dissolution and/or hydrolysis rates.

The particle size distribution of the additive when optimized will help improve fluid loss control. The rate of hydrolysis will control the rate at which the emulsion is reversed, the fracture is cleaned, and the polymer degrades. The smaller size particles will have higher surface area that will hydrolyze faster compared with larger size particles. The use of PGA, PVAc, PLA, or its copolymer, or its different degree of hydrolysis or its mixture may also be used in conjunction with other fluid loss additives, polymers, polymer breakers, crosslinked polymers, and crosslinkers.

In some cases, the additive materials may be in any shape: for example, powder, particulates, chips, fiber, bead, ribbon, tubular, platelet, film, rod, strip, spheroid, toroid, pellet, tablet, capsule, shaving, any round cross-sectional shape, any oval cross-sectional shape, trilobal shape, star shape, flat shape, rectangular shape, cubic, bar shaped, flake, cylindrical shape, filament, thread, or mixtures thereof. The additives may be solid materials, either amorphous or/and crystalline in nature, may even be hollow. Additive densities are not critical, and will preferably range from below about 0.1 to about 4 g/cm3 or more. The additives may be naturally occurring and synthetically prepared, or mixture thereof.

An effective fluid contains a reversible emulsion and an acid generating, degradable solid particulate additive. The reversible emulsion of water-in-oil contains an amphoteric surfactant with a hydrophilic end and a lipophilic end that aids in reversing the emulsion to oil-in-water when the pH is reduced towards the acid range. On increasing the pH towards the basic range the emulsion can revert back to water in oil. FIG. 1 shows a schematic of a reversible emulsion.

In some embodiments, the degradable acid generating particulates may contain poly glycolic acid (PGA), poly vinyl acetate (PVAc), poly lactic acid (PLA), or its copolymer, or its different degree of hydrolysis or its mixture. In general, any suitable acid generating compound may be used in the particulate, including, but not limited to esters, aliphatic polyesters, ortho esters, poly(ortho esters), poly(lactides), poly(glycolides), poly(e-caprolactones), poly(hydroxybutyrates), poly(anhydrides), diol esters and polyolesters such as glycol diesters and monoesters, including ethylene glycol monoesters and ethylene glycol diesters like ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol diformate, diethylene glycol monoformate, triethylene glycol diformate, triethylene glycol mono formate; glyceryl esters, mono esters, diesters or triesters including glyceryl monoformate, glyceryl diformate, glyceryl triformate, and other esters such as formate esters of pentaerythritol, and in general any esters such as acetates, propionates, butyrates, maleates, fumarates, vinyl esters, poly vinyl esters, acrylates and polyacrylates, copolymers thereof, derivatives thereof and combinations thereof. The particulate additive generates acid upon hydrolysis. Initially the solid particulate additive gets collected on to the formation face, acts as bridging agents, controls fluid loss and becomes an integral part of the filtercake through the filtration process. Subsequently, with time and temperature the particulates hydrolyze and generate acid that reverses the emulsion. The emulsion reversal helps in altering the formation wettability from oil wet to water wet thus enhancing the productivity. The deformable water droplets accumulated in the filtercake helps in the hydrolysis of the solid particulate additives and cleans up the filtercake as shown in FIG. 2. In addition the emulsion also significantly reduces the fluid loss compared with a conventional water based fluid.

The pH of the system may be controlled by adding either organic or inorganic acids that are in the solid or liquid form. Preferred mineral acids include hydrochloric acid, sulfuric acid, nitric acid, phosphoric acid, hydroflouric acid, and hydrobromic acid. Preferred organic acids include citric acid, tartaric acid, acetic acid, propionic acid, glycolic acid, lactic acid. The acid may also be generated through hydrolysis of polyanhydrides, polyesters, polyamides, polyurethanes, polyurea and polycarbonates.

The specific polymers for hydrolysis includes aliphatic polyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones); poly(hydroxybutyrates); aliphatic polycarbonates; poly(orthoesters); poly(amides); poly(urethanes); poly(hydroxy ester ethers); poly(anhydrides); aliphatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxide).

The pH control is highly desirable since it is used as a trigger to reverse the emulsion. While any suitable pH value may be used to achieve the benefits of the invention, a typical range of operation is from about 2 to about 12. At high pH (basic) the emulsion is water in oil. On lowering the pH (acidic) the emulsion becomes oil in water. Thus the water phase is now continuous. This has many advantages including the following.

• • a) Making the formation water wet that will result in improved recovery of oil.
  • b) Helping clean-up of the filtercake on the fracture surface.
  • c) Improving fracture conductivity because the pH generating solids (e.g. PLA, PGA, etc) are degradable.

An example is of PLA, PGA, polyvinyl acetate and polysuccinimide solids that will hydrolyze with time at or above about 107° C. for PLA, polyvinyl acetate and polysuccinimide, and at or below about 107° C. for PGA. These materials are capable of generating acid in situ and will reverse the emulsion. The PLA, PGA etc will initially act as fluid loss additive however with time and temperature it will degrade through hydrolysis. In some embodiments of the invention, the formation temperature range in which some methods are optimally applied are from about 49° C. to about 121° C.

Also, reversible emulsion fluids used in some embodiments may be used to transport and suspend particles such as proppant, sand, gravel, and the like, to a target area in the formation.

In some embodiments, solid particles are added stabilize emulsions, at least in part. The incorporation of solids into the emulsion may allow a slow down the breakdown of emulsion in the preparation phase, and thus require less emulsifier and less mixing time and energy. In some cases, the may help mixing the emulsion on the fly during an operation, rather than batch mixing.

EXAMPLES

The following examples are presented to illustrate the preparation and properties of fluid systems, and should not be construed to limit the scope of the invention, unless otherwise expressly indicated in the appended claims. All percentages, concentrations, ratios, parts, etc. are by weight unless otherwise noted or apparent from the context of their use.

The invention of a solid particulate additive for fluid loss control and acid generation for emulsion reversal was tested using PGA. The effect of PGA concentration on the viscosity of the emulsion with time and temperature was investigated using Fann 50 viscometer.

FIG. 3 illustrates how 2 weight percent of PGA added to the baseline (reversible water-in-oil emulsion only) lowers the viscosity at 79° C. The viscosity increases initially and thereafter decreases and remains steady for up to 15 hours. This shows that time and concentration may be tailored to control viscosity. The repeat data plot illustrates the variability in the trials. To summarize, generally, over time, the emulsion reverses.

FIG. 4 shows that at 3 weight percent of PGA, the viscosity of the emulsion increases at 79° C., 93° C. and 107° C. This feature may be desired where the fluid needs to be used as a proppant carrier and have hindered settling and may be especially important for gravel packing operations that are performed at high temperature or for clean-up operations that need particle suspension. In addition, after the initial increase in viscosity it remains constant for up to 15 hours. There is no evidence of viscosity degrading with time. The same behavior was observed at 2 weight percent PGA concentration at 79° C. That is, increased PGA concentration leads to increased viscosity in this embodiment.

FIG. 5 is a plot of fluid loss as a function of time comparing an emulsion and 3 weight percent PGA fluid for an embodiment of the invention. Adding acid generating solids (3 wt % PGA) to the fluid reduces fluid loss. This is desirable because the resulting filter cake is thinner than systems that do not have the solid PGA present.

FIG. 6 is a plot of electrical stability and pH as a function of volume of citric acid. The electrical stability drops sharply with increasing acid indicating emulsion reversal from water dispersed to water continuous phase. However, the pH gradually changes and does not follow the same slope as the electrical stability, although this trend may be not exact because it is difficult to measure pH of an emulsion. Generally, this plot indicates that the emulsion is reversing as the pH decreases. However, this plot was collected at 20° C. and the phenomena may be different for 175° C. applications.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. A method for treating a subterranean formation permeated by a wellbore, comprising:

forming a fluid comprising a reversible oil external emulsion and a degradable material;

introducing the fluid into a wellbore; and,

allowing the degradable material to degrade, whereby the emulsion is reversed.

2. The method of claim 1, wherein the degradable material is poly glycolic acid, poly vinyl acetate, poly lactic acid, copolymers thereof, fumaric acid, or a combination thereof.

3. The method of claim 1, wherein the degradable material is encapsulated.

4. The method of claim 1, wherein the reverse emulsion comprises an amphoteric surfactant.

5. The method of claim 1, wherein the introducing the fluid comprises at least one of fracturing, clean-up, stimulating, acidizing, scale removal, or fluid loss prevention along a surface of the wellbore and/or the subterranean formation.

6. The method of claim 1, wherein the degradation of the material is controlled by a change in the pH of the fluid.

7. The method of claim 1, wherein the allowing the material to degrade is controlled by the temperature of the wellbore and/or the subterranean formation.

8. The method of claim 1, wherein the allowing the material to degrade is controlled by amount of time the degradable material is exposed to the emulsion or to formation fluid.

9. The method of claim 1, wherein a concentration of the degradable material in the fluid is about 2 percent by weight or less.

10. The method of claim 1, wherein a concentration of the degradable material in the fluid is about 3 percent by weight or less.

11. The method of claim 1, wherein the fluid suspends a particle delivered to the formation at a target location.

12. The method of claim 1, wherein the fluid suspends a particle whereby the emulsion is at least partially stabilized by the particle.

13. A method for treating a subterranean formation permeated by a wellbore, comprising:

forming a fluid comprising a reversible oil external emulsion and a fluid loss additive;

introducing the fluid into a wellbore; and,

allowing the fluid loss additive to degrade.

14. The method of claim 13, wherein the fluid loss additive is poly glycolic acid, poly vinyl acetate, poly lactic acid, copolymers thereof, fumaric acid, or a combination thereof.

15. The method of claim 13, wherein the fluid loss additive is encapsulated.

16. The method of claim 13, wherein the reverse emulsion comprises an amphoteric surfactant.

17. The method of claim 13, wherein the introducing the fluid comprises fracturing, clean-up, stimulating, and/or fluid loss preventing along a surface of the wellbore and/or the subterranean formation.

18. The method of claim 13, wherein the allowing the fluid loss additive to degrade is controlled by change of fluid pH.

19. The method of claim 13, wherein the allowing the fluid loss additive to degrade is controlled by the temperature of the wellbore and/or the subterranean formation.

20. The method of claim 13, wherein the allowing the fluid loss additive to degrade is controlled by the time the degradable material is exposed to the reversible emulsion.

21. The method of claim 13, wherein a concentration of the fluid loss additive in the fluid is about 2 percent by weight or less.

22. The method of claim 13, wherein a concentration of the fluid loss additive in the fluid is about 3 percent by weight or less.

23. The method of claim 13, wherein the fluid suspends a particle delivered to the formation at a target location.

24. A method of fracturing a subterranean formation penetrated by a wellbore, the method comprising:

forming a fluid comprising a reversible oil external emulsion, a degradable material, and a particle;

introducing the fluid into a wellbore at a pressure meeting or exceeding the fracture initiation pressure of the formation; and,

allowing the degradable material to degrade.