Composition and method for improving the production of petroleum hydrocarbons

Abstract

A novel surfactant composition that comprises of two surfactant components, a solvent, and water. The surfactant composition is added to a fracturing fluid, which is then pumped downhole into a subterranean formation where the novel characteristics of the fracturing fluid lend to improved oil production over the fracturing fluid without the surfactant composition.

Claims

1. A surfactant solution for use as an additive in a hydraulic fracturing fluid comprising: a mixture of a first surfactant, a second surfactant, a solvent, and water: wherein the first surfactant is an ether sulfonate anionic surfactant of the formula: R.sub.1O(R.sub.2O).sub.x(R.sub.3O).sub.yCH.sub.2CH(OH)CH.sub.2SO.sub.3M, wherein R.sub.1 is a linear or branched alkyl group having 5 to 30 carbon atoms, R.sub.2 is —CH.sub.2CH.sub.2—, R.sub.3 is —CH(CH.sub.3)CH.sub.2—, x is an integer from 2 to 30, y is an integer from 0 to 20, and M is a monovalent cation; wherein the second surfactant is an alkyl alkoxylated nonionic surfactant of the formula R.sub.4O(R.sub.2O).sub.m(R.sub.3O).sub.nH, where R.sub.4 is a linear or branched alkyl group having 5 to 30 carbon atoms, m is an integer from 5 to 30, and n is an integer from 1 to 20; wherein the solvent is methanol, ethanol, isopropanol, 1-propanol, butanol, acetone, ethyl lactate, glycerol, ethylene glycol, ethylene glycol butyl ether, butyl acetate, acetic acid, or any combination thereof; and wherein the surfactant solution is added to a hydraulic fracturing fluid.

2. The surfactant solution of claim 1 wherein the concentration of the first surfactant in the surfactant solution is from about 1 wt. % to 65 wt. %.

3. The surfactant solution of claim 2 wherein the concentration of the first surfactant in the surfactant solution is from about 5 wt. % to 55 wt. %.

4. The surfactant solution of claim 3 wherein the concentration of the first surfactant in the surfactant solution is from about 10 wt. % to 45 wt. %.

5. The surfactant solution of claim 1 wherein the concentration of the second surfactant in the surfactant solution is from about 1 wt. % to 80 wt. %.

6. The surfactant solution of claim 5 wherein the concentration of the second surfactant in the surfactant solution is from about 15 wt. % to 65 wt. %.

7. The surfactant solution of claim 6 wherein the concentration of the second surfactant in the surfactant solution is from about 30 wt. % to 50 wt. %.

8. The surfactant solution of claim 1 wherein the concentration of the solvent in the surfactant solution is from about 1 wt. % to 90 wt. %.

9. The surfactant solution of claim 8 wherein the concentration of the solvent in the surfactant solution is from about 5 wt. % to 50 wt. %.

10. The surfactant solution of claim 9 wherein the concentration of the solvent in the surfactant solution is from about 10 wt. % to 35 wt. %.

11. The surfactant solution of claim 1 wherein the concentration of water in the surfactant solution is from about 1 wt. % to 90 wt. %.

12. The surfactant solution of claim 11 wherein the concentration of water in the surfactant solution is from about 15 wt. % to 60 wt. %.

13. The surfactant solution of claim 12 wherein the concentration of water in the surfactant solution is from about 30 wt. % to 45 wt. %.

14. The surfactant solution of claim 1 wherein the water comprises sodium chloride and calcium chloride and the concentration of sodium chloride in the water is up to 25.0 wt. % and the concentration of calcium chloride in the water is up to 5.0 wt. %.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) In order that the manner in which the above-recited and other enhancements and objects of the disclosure are obtained, a more particular description of the disclosure briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only typical embodiments of the disclosure and are therefore not to be considered limiting of its scope, the disclosure will be described with additional specificity and detail through the use of the accompanying drawings in which:

(2) FIG. 1 depicts a photo of the contact angle of a single 5 μL drop of Brine #1 without surfactant that was placed on a Parker sandstone core that had been saturated with crude oil and aged at 176° F. for three weeks;

(3) FIG. 2 depicts a photo of the contact angle of a single 5 μL drop of Brine #1 with 1 gpt surfactant solution #1 that was placed on a Parker sandstone core that had been saturated with crude oil and aged at 176° F. for three weeks;

(4) FIG. 3 depicts a photo of the contact angle of a single 5 μL drop of Brine #1 with 1 gpt surfactant solution #2 that was placed on a Parker sandstone core that had been saturated with crude oil and aged at 176° F. for three weeks;

(5) FIG. 4 depicts a photo of the contact angle of a single 5 μL drop of Brine #1 with 1 gpt surfactant solution #3 that was placed on a Parker sandstone core that had been saturated with crude oil and aged at 176° F. for three weeks;

(6) FIG. 5 depicts a graph of interfacial tensions (IFT) that were measured between crude oil and Brine #1 with 1 gpt surfactant solution #1 (aged and unaged at 320° F. for four days) The temperature was increased from room temperature to 176° F., and then was maintained at 176° F. for over 1.5 hours during the IFT measurement;

(7) FIG. 6 depicts a graph of interfacial tensions that were measured between crude oil and Brine #1, crude oil and Brine #2, crude oil and Brine #3, crude oil and Brine #4, each with 1 gpt Surfactant Solution #1.

(8) FIG. 7 depicts a graph of interfacial tensions that were measured between crude oil and Brine #2 and crude oil and Brine #5, each with 1 gpt Surfactant Solution #1.

(9) FIG. 8 depicts a graph of cumulative oil recovery rates of the spontaneous imbibition tests at 176° F. for Brine #1 with and without 1 gpt surfactant solution #1.

DETAILED DESCRIPTION

(10) The particulars shown herein are by way of example and for purposes of illustrative discussion of the preferred embodiments of the present disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of various embodiments of the disclosure. In this regard, no attempt is made to show structural details of the disclosure in more detail than is necessary for the fundamental understanding of the disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the disclosure may be embodied in practice.

(11) The following definitions and explanations are meant and intended to be controlling in any future construction unless clearly and unambiguously modified in the following examples or when application of the meaning renders any construction meaningless or essentially meaningless. In cases where the construction of the term would render it meaningless or essentially meaningless, the definition should be taken from Webster's Dictionary 3.sup.rd Edition.

(12) Anionic Surfactants, Nonionic Surfactants, and Solvents

(13) Anionic Surfactants #1-3:

(14) The ether sulfonate (anionic surfactants) tested herein have the following formula:
R.sub.1O(R.sub.2O).sub.x(R.sub.3O).sub.yCH.sub.2CH(OH)CH.sub.2SO.sub.3M
Where R.sub.1 is C.sub.11 to C.sub.14 iso-alkyl, R.sub.2 is ethyl, and R.sub.3 is propyl with structure of CH(CH.sub.3)CH.sub.2.
Anionic surfactant #1: x=9 and y=4;
Anionic surfactant #2: x=9 and y=12;
Anionic surfactant #3: x=18 and y=0.
Nonionic Surfactants #1-3:

(15) The alkyl alkoxylated nonionic surfactants tested herein have the following formula:
R.sub.1O(R.sub.2O).sub.m(R.sub.3O).sub.nH
Where R.sub.4 is C.sub.11 to C.sub.14 iso-alkyl, R.sub.2 is ethyl, R.sub.3 is propyl with structure of CH(CH.sub.3)CH.sub.2.
Nonionic #1: m=18 and n=1;
Nonionic #2: m=9 and n=4;
Nonionic #3: m=9 and n=12.
Solvents

(16) In an embodiment, the solvent is at least one or any combination of the solvents including, but not limited to, methanol, ethanol, isopropanol, 1-propanol, butanol, acetone, ethyl lactate, glycerol, ethylene glycol, ethylene glycol butyl ether, butyl acetate, and acetic acid. In an embodiment, the solvent is one or any combination of solvents known to one of ordinary skill in the art for use in a wellbore.

(17) In an embodiment, ethylene glycol butyl ether can be used as a solvent in the surfactant solution. Ethylene glycol butyl ether (Solvent #1) tested herein has the following structure:
CH.sub.3CH.sub.2CH.sub.2CH.sub.2OCH.sub.2CH.sub.2OH
Surfactant Solutions

(18) In an embodiment, various surfactant solutions were made by combining an anionic surfactant, a nonionic surfactant, a solvent, and water.

(19) TABLE-US-00001 TABLE 1 Surfactant Solutions #1-3 Surfactant Surfactant Surfactant solution #1 solution #2 solution #3 Anionic #1: Anionic #2: Anionic #3: 13.0 wt. % 13.0 wt. % 14.8 wt. % Nonionic #1: Nonionic #2: Nonionic #3: 43.0 wt. % 35.2 wt. % 34.2 wt. % Solvent #1: Solvent #1: Solvent #1: 11.4 wt. % 9.3 wt. % 9.2 wt. % Water: 32.6 Water: 42.5 Water: 41.8 wt. % wt. % wt. %
Brines

(20) In an embodiment, various brines were made by mixing sodium chloride and calcium chloride in deionized water. In an embodiment, a brine can contain one or more of sodium chloride, calcium chloride, potassium chloride, magnesium chloride, sodium sulfate, and potassium sulfate.

(21) TABLE-US-00002 TABLE 2 Brines #1-5 Brine #1 Brine #2 Brine #3 Brine #4 Brine #5 NaCl (wt %) 3.0 10.0 15.0 20.0 10.0 CaCl.sub.2 (wt %) 0.5 0.5 0.5 0.5 2.0

Example 1. Wettability Tests

(22) As illustrated in FIG. 1, FIG. 2, FIG. 3, and FIG. 4, a single drop of brine #1 of 5 μL with and without adding surfactant solutions was placed on Parker sandstone cores which had been saturated with crude oil with an API gravity of 41.7 degrees and aged at 176° F. for 3 weeks. For FIG. 1, FIG. 2, FIG. 3, and FIG. 4, the drops of brine #1 were without adding any surfactant solution, with 1 gpt surfactant solution #1, with 1 gpt surfactant solution #2, and with 1 gpt surfactant solution #3, respectively. As illustrated in FIG. 1, FIG. 2, FIG. 3, and FIG. 4, the contact angles measured were 117°, 73°, 67°, and 72°, respectively, which indicates that the surfactant solutions changed the wettability of the core surfaces from oil-wet (contact angle>90°) to water-wet (contact angle<90°).

Example 2. Thermal Stability Tests

(23) Thermal stability of the surfactant solutions was tested by comparing the interfacial tensions of the surfactant solutions both aged and unaged at 320° F. for 4 days with a “KRUSS spinning drop tensiometer SDT”. The interfacial tensions were measured between Brine #1 with 1 gpt surfactant solution #1 and crude oil with an API gravity of 41.7 degrees as the temperature increased from room temperature to 176° F. and maintained at 176° F. FIG. 5 shows the curves of the interfacial tension vs. time for the surfactant both aged and unaged are almost overlapped which indicates the surfactant is quite thermally stable at 320° F.

Example 3. Salinity and Hardness Compatibility Tests

(24) The salinity and hardness compatibility of the surfactant solutions was tested by measuring the interfacial tensions between crude oil and brine with 1 gpt surfactant solutions and different salinity and hardness. The API gravity of the crude oil is 41.7 degrees. FIG. 6 and FIG. 7 show the interfacial tension of the crude oil with Brine #1, Brine #2, Brine #3, Brine #4, or Brine #5 with 1 gpt surfactant solution #1. Various Brines have different salinity and hardness. FIG. 6 shows, as the concentration of sodium chloride increases, the interfacial tension decreases which indicates the surfactant solution is compatible with high salinity. FIG. 7 shows, as the concentration of calcium chloride increases from 0.5 wt. % (Brine #2) to 2.0 wt. % (Brine #5), the interfacial tension slightly decreases which indicates the surfactant solution is compatible with high hardness.

Example 4. Oil Recovery Tests

(25) Spontaneous imbibition tests were used to evaluate the performance of the surfactant solutions on improving and increasing oil recovery. Parker sandstone cores with porosity and permeability about 14% and 6 and respectively were used for the spontaneous imbibition tests. The cores were dried for 24 hours at 176° F., saturated with crude oil with an API gravity of 41.7 degrees, aged at 176° F. for 3 weeks, and then used for the spontaneous imbibition tests. FIG. 8 shows the cumulative oil recovery rates of the spontaneous imbibition tests at 176° F. for Brine #1 with and without 1 gpt surfactant solution #1. The final oil recovery rates are 40.4% OOIP and 28.4% OOIP for the brine with and without surfactant solution, respectively. OOIP stands for original oil-in-place.

(26) All of the compositions and methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this disclosure have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and methods and in the steps or in the sequence of steps of the methods described herein without departing from the concept, spirit and scope of the disclosure. More specifically, it will be apparent that certain agents which are both chemically related may be substituted for the agents described herein while the same or similar results would be achieved. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the disclosure as defined by the appended claims.