US20140158359A1

US20140158359A1 - Methods for Increasing Subterranean Formation Permeability

Info

Publication number: US20140158359A1
Application number: US13/706,930
Authority: US
Inventors: Eric Davidson; Steven Ray Blattel
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2012-12-06
Filing date: 2012-12-06
Publication date: 2014-06-12
Also published as: AR093868A1; WO2014089147A1

Abstract

Methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore using non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst or enzyme. Some methods comprise providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into a subterranean formation at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate into at least a portion of the subterranean formation; and leaving the treatment fluid in contact with the subterranean formation for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.

Description

BACKGROUND

The present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
While fracturing operations are known to be useful in increasing the available flow pathways from the formation to the wellbore, the flow of fluids through the formation itself, en route to the fracture, remains limited by the permeability of the surrounding formation. That is, the flow of oil from a subterranean formation to a well bore depends, among other factors, upon the degree of permeability of the formation. Often, the permeability is not sufficiently great to permit a desired rate of fluids, e.g., crude oil, natural gas, etc., from the formation. In such a case, the formation can be treated to increase its permeability. Acidizing is a process for dissolving material from a formation to improve production.
Acidizing fluids have been used to increase the productivity of oil and gas from calcareous formations by effecting the removal of reactive materials from naturally occurring fractures and pore spaces in the formations whereby the sizes thereof are increased. Acidizing fluids also have been used to create new fractures in formations with the acid acting to etch the fractures so that they remain open and have a high flow capacity.
The rate at which acidizing fluids react with reactive materials in a formation is a function of various factors including acid concentration, temperature, velocity, the type of reactive material encountered, etc. Whatever the rate of reaction, the acidizing fluid can be introduced into the formation only a certain distance before it becomes spent. The time required for the acidizing fluid to become spent is referred to herein as “reaction time.” In creating new fractures in a formation, if the acidizing fluid is pumped under pressure further into the formation after it has become spent, it may extend fractures in the formation, but it may not increase the flow capacities of the extended fractures. The fractures may close completely when the pressure is relieved. Thus, it is important to extend the reaction time of acidizing fluids so that either or both reactive materials are removed and new fractures are etched for as great a distance into the formation from the well bore as possible.

SUMMARY OF THE INVENTION

The present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
Some embodiments of the present invention provide methods comprising: providing a subterranean formation that has been fractured; providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into the fracture at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate into at least a portion of the subterranean formation surrounding the fracture; and leaving the treatment fluid in contact with the subterranean formation surrounding the fracture for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.
Other embodiments of the present invention provide methods comprising: providing a subterranean formation surrounding a wellbore; providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid; introducing the treatment fluid into a portion of the subterranean formation surrounding a wellbore at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate the formation; and leaving the treatment fluid in contact with the subterranean formation surrounding a wellbore for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.
The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

DETAILED DESCRIPTION

The present invention relates to methods for increasing the permeability of a portion of a subterranean formation surrounding a wellbore. More particularly, the present invention relates to the use of non-hydrolyzed liquid esters to attack carbonates within acid-soluble formations without requiring the use of a catalyst.
In some embodiments, the present invention provides a method of treating a portion of a carbonate-containing subterranean formation to increase the formation permeability. A treatment fluid comprising a non-hydrolyzed liquid ester is introduced into the portion of the subterranean formation and allowed to penetrate into the formation at matrix rate/pressure. Once placed, the non-hydrolyzed liquid ester is allowed to remain in contact with the portion of the subterranean formation. Over time under formation temperature, the non-hydrolyzed liquid ester hydrolyzes to produce an acid that is capable of chemically attacking the carbonate portions of the formation to create additional porosity and permeability therein. That is because as the acid is produced and contacts the solid carbonates within the formation, the two react to form a salt, carbon dioxide, and water, thus removing at least a portion of the solid formation. The methods of the present invention are able to generate an acid to increase formation permeability using a non-hydrolyzed liquid ester without the necessity of any catalyst or enzyme. Rather, the acid is generated directly from the non-hydrolyzed liquid ester in contact with water over time and temperature.
In the methods of the present invention, because the acid is only generated over time, the non-hydrolyzed liquid ester is able to penetrate deep into the formation before the acid is created and consumed in the carbonate attack. Because of this, the methods of the present invention are capable of increasing permeability deep in the formation, rather than just at the fracture face. The methods of the present invention are suitable for use in any acid-soluble formation make-up, but may be particularly useful in limestone, dolomitic, or chalk formations. However, the methods of the present invention may be less suited for use in sandstone formations, which often has acid soluble material as the inter-grain cementing material and so the introduction of the proposed non-hydrolyzed liquid esters destabilize the treated section.
Generally, the non-hydrolyzed liquid ester is placed into a portion of the subterranean formation as part of a larger treatment fluid. The treatment fluid comprises a base fluid and may comprise additional additives as well.
Generally, the non-hydrolyzed liquid esters are included in the treatment fluid in an amount ranging from about 5% to about 40% by volume of the treatment fluid. In some preferred embodiments, the non-hydrolyzed liquid esters are included in the treatment fluid in an amount ranging from about 10% to about 30% by volume of the treatment fluid.
Suitable base fluids for use in conjunction with the present invention are generally aqueous-based fluids such as fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, and any combination thereof. Brines may be particularly preferred. Any brine known in the art may be suitable for use in the methods of the present invention, such as calcium-bromide, magnesium-bromide, potassium-bromide, sodium-bromide; calcium-chloride, magnesium-chloride, potassium-chloride, or sodium-chloride; and combinations thereof. In some embodiments, the brine may comprise salts of monovalent cations or salts of organic acids, such as formate brines or acetate brines.
Suitable non-hydrolyzed liquid esters for use in the present invention may include, but are not limited to formate esters, acetate esters, and lactate esters. By way of example, the non-hydrolyzed liquid ester may be diethylene glycol diformate, a glycolate, glycerin triacetate (also known as triacetin), glycerin diacetate (also known as diacetin), ethyl lactate, acetate esters, methyl lactate, ethylene glycol monoformate, ethyl formate, methyl formate, or a combination thereof. In some preferred embodiments, the non-hydrolyzed liquid ester for use in the present invention is a formate ester or a combination of formate esters. One of skill in the art will recognize that selection of the non-hydrolyzed liquid ester will be dependent, at least in part, on the temperature of the formation being treated. By was of example, ethyl lactate reacts too slowly at 70° C. to be suitable for use in treating formations at that temperature. Whereas diethylene glycol diformate and ethylene glycol monoformate may be well-suited for treatment at 70° C., but less well suited for a higher temperature formation. By way of example, diethylene glycol diformate is well-suited for formation temperatures up to about 90° C. and ethyl lactate is well-suited for formation temperatures above 90° C. and as high as 150° C.
Once the non-hydrolyzed liquid ester is placed into a subterranean formation, it must be allowed to remain in contact for a period of time ranging from about 1 hour and above. One of skill in the art will recognize that there is no upper limit necessary from a technical perspective for the contact time; however, one of skill will also recognize that lengthy shut-in time for a well may be cost prohibitive. In some preferred embodiments, the contact time may range from about 2 hours to about 72 hours. One of skill in the art will recognize that the particular non-hydrolyzed liquid ester selected and the temperature of the subterranean formation will each affect the necessary length of time to allow for the ester to hydrolyze and for the resulting acid to react with the carbonates within the formation.
Generally, the methods of the present invention are well suited for subterranean formations that exhibit a natural temperature of at least about 50° C., preferably at least about 70° C. While lower temperature formations can be treated with the methods of the present invention, the time it takes for the ester to hydrolyze may make the methods impractical in that they would require lengthy shut-in periods. Similarly, formations that exhibit temperatures greater than 175° C. may result in such rapid hydrolysis of the ester that the penetration into the formation is less than desired.
Preferably, the non-hydrolyzed liquid ester is placed deep into the formation to provide a wide area of treatment. In some preferred embodiments, the non-hydrolyzed liquid ester is placed at least about 300 cm into the formation before the acid is spent. In other preferred embodiments, the non-hydrolyzed liquid ester may be placed several meters into the formation before the acid is spent.
In some embodiments, the treatment fluid comprising a non-hydrolyzed liquid ester is placed into the formation surrounding a fracture directly after the fracturing treatment is completed and before the fracture pressure has been released. However, the treatment fluid itself is not put into the formation at a pressure sufficient to cause additional fracturing, rather it is placed at matrix rates. In other embodiments, the treatment fluid comprising a non-hydrolyzed liquid ester may be placed directly into a subterranean formation, with or without a fracture being formed in advance.
Prior to the introduction of the treatment fluid of the present invention, a pre-flush fluid may first be introduced into the subterranean formation. Pre-flush fluids may aid in removing debris from the flow path, displacing reservoir fluids, and/or preconditioning the unconsolidated particulates for accepting the non-hydrolyzed liquid ester. Suitable examples of pre-flush fluids for use in the methods of the present invention may include, but are not limited to aqueous fluids, solvent-based fluids, or gas-based fluids. The aqueous pre-flush fluid may comprise, for example, fresh water; saltwater; brine and any combinations thereof. The aqueous pre-flush fluids may be from any source, provided that they do not contain components that adversely affect the stability and/or performance of the treatment fluids of the present invention. In other embodiments, solvent-based pre-flush fluids may comprise a glycol ether solvent, such as diethylene glycol monomethyl ether; diethylene glycol dimethyl ether; ethylene glycol monobutyl ether; diethylene glycol monobutyl ether, dipropylene glycol monomethyl ether; or any combinations thereof. In those embodiments where a gas pre-flush fluid is applied, the fluid may be applied in an amount from about 25 to about 200 cubic feet per foot of the interval to be treated, depending on the temperature and pressure of the interval of interest. In accordance with the teachings of the present invention, a pre-flush may be performed multiple times, as needed. Multiple pre-flush treatments may include the same or different pre-flush fluids.
Introduction of the treatment fluid of the present invention may be followed by the application of a post-flush fluid. The post-flush fluid may facilitate removal of excess treatment fluid from the pore spaces in the subterranean formation and may enhance post-treatment permeability. Examples of suitable post-flush fluids include, but are not limited to, a gas (e.g., air, nitrogen, and the like); an aqueous fluid, a foamed aqueous fluid (e.g., a brine); and a hydrocarbon fluid (e.g., diesel, kerosene, and the like). In those embodiments where a gas post-flush fluid is applied, the fluid may be applied in an amount from about 25 to about 200 cubic feet per foot of the interval to be treated, depending on the temperature and pressure of the interval of interest. In embodiments where a foamed aqueous post-flush fluid is applied, the fluid may be applied in an amount from about one to two times the volume of the treatment fluids used. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate type and amount of post-flush fluid to include in the methods of the present invention.
In some embodiments, the pre-flush, treatment, and post-flush of the present invention may further comprise one or more additives suitable for use in the particular subterranean operation. Any additives useful in a subterranean operation may be included in the pre-flush, treatment, and post-flush of the present invention provided that they do not interfere with the non-hydrolyzed liquid ester. Suitable additives may include, but are not limited to, a salt, a weighting agent, an inert solid, a fluid loss control agent, an emulsifier, a dispersion aid, a corrosion inhibitor, an emulsion thinner, an emulsion thickener, a viscosifying agent, a gelling agent, a surfactant, a particulate, a proppant, a gravel particulate, a lost circulation material, a foaming agent, a gas, a pH control additive, a breaker, a biocide, a crosslinker, a stabilizer, a chelating agent, a mutual solvent, a reducer, a friction reducer, a clay stabilizing agent, and any combinations thereof.
The pre-flush, treatment, and post-flush fluids of the present invention may be prepared by any method suitable for a given subterranean operation. For example, certain components of the treatment fluids may be provided in a pre-blended powder, solid, or liquid form, which may be combined with the treatment fluids of the present invention at a subsequent time. In general, the pre-flush, treatment, and post-flush fluids of the present invention may be bullheaded into the well (i.e., pumped into the wellbore without the use of isolation tools or barrier devices) or placed using coiled tubing or jointed pipe to treat specific intervals of interest. In some embodiments, a pressure pulsing or rotating hydrojetting tool may be coupled with the coiled tubing or jointed pipe to aid in placement of the treatment or post-flush fluids in the subterranean formation.
To facilitate a better understanding of the present invention, the following examples of preferred or representative embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention.

EXAMPLES

Example 1

One medium permeability limestone core and one low permeability limestone core were tested for initial and post-treatment permeability. Before testing began, each core was vacuum saturate with 3% KCl bine overnight. The medium permeability limestone core had an initial permeability of 153 mD and the low permeability limestone core had an initial permeability of 5.8 mD. Each of the cores was injected with a 10% by volume of diethylene glycol diformate in a sodium bromide brine having a specific gravity of 1.2. The injected cores were then held static for 16-hours at 70° C. Following the hold period, the permeability was re-checked and the medium permeability limestone core had a revised permeability of 192 mD (a 25% increase) and the low permeability limestone core had an initial permeability of 14.7 mD (a 153% increase).

Example 2

A low permeability core was injected with a 10% by volume of ethyl lactate in a sodium bromide brine having a specific gravity of 1.2. Before testing began, the core was vacuum saturated with 3% KCl brine overnight.
The injected core was then held static for 48-hours at 70° C. No significant increase in permeability was detected. As a follow-up, a low permeability core was injected with a 17.5% by volume of ethyl lactate in a sodium bromide brine having a specific gravity of 1.2. Before testing began, the core was vacuum saturated with 3% KCl brine overnight. The injected core was held static at 120° C. for 48 hours. Again, no increase in permeability was detected.

Example 3

A limestone core was initially evaluated to determine average pore diameters. The results show that 90% of the pores were 0.34 microns or smaller (D₉₀=0.34), 50% of the pores were 0.25 microns or smaller (D₅₀=0.25), and 10% of the pores were 0.14 microns or smaller (D₁₀=0.14). The limestone core was then treated with 17.5% vol ethyl lactate in a sodium bromide brine having a specific gravity of 1.2, the fluid was left in contact with the core at 120° C. for 48 hours. After treatment, the pore diameters were retested and showed that 90% of the pores were 0.81 microns or smaller (D₉₀=0.81), 50% of the pores were 0.45 microns or smaller (D₅₀=0.45), and 10% of the pores were 0.26 microns or smaller (D₁₀=0.26).

Example 4

Two limestone cores were initially evaluated to determine average pore diameters before and after treatment. The cores analyzed were treated with 10% by volume diethylene glycol diformate in a 1.2 specific gravity sodium bromide brine at 70° C. for 16 hours. The pore diameter results were as follows:


	Average pore diameter

	Medium	Medium	Low	Low
	Permeability	Permeability	Permeability	Permeability
Size	Core Before	Core After	Core Before	Core After
Percentage	Treatment	Treatment	Treatment	Treatment

D10	0.5 microns	120 microns	0.1 microns	0.5 microns
D50	1.1 microns	230 microns	0.2 microns	0.9 microns
D90	2.8 microns	370 microns	0.3 microns	1.6 microns

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present 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 of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A method comprising:

providing a subterranean formation that has been fractured;

providing a treatment fluid comprising a non-hydrolyzed liquid ester in a base fluid;

introducing the treatment fluid into the fracture at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate into at least a portion of the subterranean formation surrounding the fracture, wherein the step of introducing the treatment fluid into the fracture at matrix flow rates causes the non-hydrolyzed liquid ester to penetrate into the formation to a depth of at least about 300 cm; and

leaving the treatment fluid in contact with the subterranean formation surrounding the fracture for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.

2. The method of claim 1 wherein the non-hydrolyzed liquid ester hydrolyzes to produce an acid without the presence of a catalyst or enzyme.

3. The method of claim 1 wherein the non-hydrolyzed liquid ester comprises a formate ester, a lactate ester, and any combination thereof.

4. The method of claim 1 wherein the non-hydrolyzed liquid ester comprises diethylene glycol diformate, a glycolate, glycerin triacetate, glycerin diacetate, ethyl lactate, an acetate ester, methyl lactate, ethylene glycol monoformate, an ethyl formate, a methyl formate, and any combination thereof.

5. (canceled)

6. The method of claim 1 wherein the period of time is at least about 2 hours.

7. The method of claim 1 wherein the subterranean formation surrounding the fracture has a temperature above about 50° C. and below about 175° C.

8. The method of claim 1 wherein the non-hydrolyzed liquid ester is present in the treatment fluid in an amount ranging from about 5% to about 40% by volume of the treatment fluid.

9. The method of claim 1 wherein the base fluid is an aqueous fluid.

10. A method comprising:

providing a subterranean formation surrounding a wellbore;

introducing the treatment fluid into a portion of the subterranean formation surrounding a wellbore at matrix flow rates to allow the non-hydrolyzed liquid ester to penetrate the formation, wherein the step of introducing the treatment fluid into the fracture at matrix flow rates causes the non-hydrolyzed liquid ester to penetrate into the formation to a depth of at least about 300 cm; and

leaving the treatment fluid in contact with the subterranean formation surrounding a wellbore for a period of time during which at least a portion of the non-hydrolyzed liquid ester hydrolyzes to produce an acid.

11. The method of claim 10 wherein the non-hydrolyzed liquid ester hydrolyzes to produce an acid without the presence of a catalyst or enzyme.

12. The method of claim 10 wherein the non-hydrolyzed liquid ester comprises a formate ester, a lactate ester, and any combination thereof.

13. The method of claim 10 wherein the non-hydrolyzed liquid ester comprises diethylene glycol diformate, a glycolate, glycerin triacetate, glycerin diacetate, ethyl lactate, an acetate ester, methyl lactate, ethylene glycol monoformate, an ethyl formate, a methyl formate, and any combination thereof.

14. (canceled)

15. The method of claim 10 wherein the period of time is at least about 2 hours.

16. The method of claim 10 wherein the subterranean formation surrounding the fracture has a temperature above about 50° C. and below about 175° C.

17. The method of claim 10 wherein the non-hydrolyzed liquid ester is present in the treatment fluid in an amount ranging from about 5% to about 40% by volume of the treatment fluid.

18. The method of claim 10 wherein the base fluid is an aqueous fluid.