Well Service Fluid Composition and Method of Using Microemulsions as Flowback Aids

Abstract

The present invention relates to a new Winsor type IV microemulsion system for faster return of well service fluid and enhanced production of hydrocarbon-containing fluids in fractured tight subterranean formations, where the microemulsion system includes a surfactant subsystem including at least one glucamide sugar surfactant, a solvent subsystem and a co-solvent subsystem and to methods for making and using same.

Claims

1. Microemulsion, comprising water, 2-15 wt.-% of at least one organic solvent with flash point above 37.8° C. (100° F.) and pour point of 10° C. or lower, 1-6 wt.-% of at least one co-solvent that includes at least one alcohol, and 12-30 wt.-% of at least one N-Alkyl-N-acylglucamine surfactant, which is a Winsor type IV emulsion.

2. Microemulsion according to claim 1, wherein the glucamide surfactant is a compound of formula (I) ##STR00003## wherein Ra is a C.sub.5-C.sub.21-hydrocarbon residue, and Rb is a C.sub.1-C.sub.4-alkyl group.

3. Microemulsion according to claim 1, wherein the glucamide surfactant is a compound according to formula (II) ##STR00004## wherein Ra is a C.sub.5-C.sub.21-hydrocarbon residue, and Rb is a C.sub.1-C.sub.4-alkyl group.

4. Microemulsion according to claim 1, wherein the glucamide surfactant is a compound according to formula (III) ##STR00005## wherein Ra is a C.sub.5-C.sub.21-hydrocarbon residue, and Rb is a C.sub.1-C.sub.4-alkyl group.

5. Microemulsion according to claim 1, wherein the glucamide surfactant is a compound according to formula (IV) ##STR00006## wherein Ra is a C.sub.5-C.sub.21-hydrocarbon residue, and Rb is a C.sub.1-C.sub.4-alkyl group.

6. Microemulsion according to one or more of claims 1-5, wherein Ra is C.sub.7 to C.sub.15 hydrocarbon.

7. Microemulsion according to one or more of claims 1-6, wherein Ra is an aliphatic group.

8. Microemulsion according to one or more of claims 1-7, wherein Ra is alkyl or alkenyl.

9. Microemulsion according to one or more of claims 1-8, wherein Rb is methyl.

10. Microemulsion according to one or more of claims 1-9, wherein in at least 50 wt.-% of the total amount of compounds according to formula (I) Ra is C.sub.7 to C.sub.9 alkyl and in up to 50 wt.-% Ra is C.sub.11 to C.sub.13 alkyl.

11. Microemulsion according to one or more of claims 1-10, wherein the first solvent is selected from the group consisting of naphthalene depleted alkyl arenes, terpenes, paraffinic solvents, fatty acid alkyl esters and butyl glycol ethers.

12. Microemulsion according to one or more of claims 1-11, wherein the co-solvent is selected from the group consisting of primary, secondary or tertiary monoalcohols having from 1-20 carbon atoms, and diols having from 1-20 carbon atoms.

13. Microemulsion according to one or more of claims 1-12, wherein the co-solvent is selected from the group consisting of propylene glycol, isopropanil, t-butanol, n-butanol, n-pentanol, n-hexanol, n-octanol and pentane-diol.

14. Microemulsion according to one or more of claims 1-13, further comprising a mutual solvent selected from the group consisting of 2-ethylhexanol and ethers of 2-ethylhexanol with ethylene glycol, polyethylene glycols or propylene glycol.

15. Microemulsion according to one or more of claims 1-14, comprising 14-25 wt.-% of the glucamide surfactant.

16. Microemulsion according to one or more of claims 1-15, comprising 3-5 wt.-% of the co-solvent.

17. Microemulsion according to one or more of claims 1-16, comprising 5-10 wt.-% of the first solvent.

18. Microemulsion according to one or more of claims 1-17, comprising up to 10 wt.-% of a mutual solvent.

19. Microemulsion according to one or more of claims 1-18, comprising water ad 100 wt.-%.

20. Process for recovering fluids during fracturing operations, the process comprising injecting a microemulsion according to one or more of claims 1-19 into the fractured formation.

21. Process according to claim 20, wherein the amount of microemulsion is 0.1 to 10 gallons of microemulsion per thousand gallons of fracturing fluid (0.01-1% by volume).

22. Process for stimulating an oil or gas well, comprising injection of water and a microemulsion according to one more of claims 1-21.

23. Process according to claim 22, wherein 0.1 to 10 gallons of microemulsion are used per 1000 gallons of water (0.01-1% by volume).

24. Use of a microemulsion according to one or more claims 1-19 as flowback aid during fracturing operations.

25. Use according to claim 24, wherein 0.1 to 10 gallons (0.01-1% by volume) of microemulsion are used per 1000 gallons of treatment fluid injected into oil or gas well.

26. Use of a microemulsion according to one or more of claims 1-19, in stimulating an oil or gas well by injection of water based fluids.

27. Use according to claim 26, wherein 0.1 to 10 gallons (0.01%-1% by volume) of microemulsion are used per 1000 gallons of injected water.

Description

EXAMPLES

[0051] In this specification, all percentages refer to % by weight if not otherwise noted.

Example 1: Composition

[0052] An overview of different compositional aspects of this invention is given in Table 1.

[0053] The different materials are as follows: [0054] a) water is either potable or 3 wt.-% KCl solution; [0055] b) solvents Caromax® 20 LN is naphthalene depleted heavy aromatic naphtha, Sipdril® 1LV is a paraffinic base oil, FAME is rape seed oil methyl ester; [0056] c) the glucamide C.sub.8-C.sub.10, C.sub.8-C.sub.14 and C.sub.8-C.sub.18 is a N-Alkyl-N-acylglucamine with C.sub.8-C.sub.10, C.sub.8-C.sub.14 and C.sub.8-C.sub.18 alkyl chain length respectively, as main surfactant component with high cloud point and insensitive to high salinities; [0057] d) Genapol® X 060, LA040, UD30 and UD110 are ethoxylated alcohols with isotridecyl chain and six moles of ethylene oxide (EO), C.sub.12-C.sub.14 alkyl chain with 4 moles of ethylene oxide (EO), undecyl chain with 3 and 11 moles of ethylene oxide, respectively, and are used as co-surfactants; [0058] e) Propylene glycol, Polyethylene glycol (PEG-400), Polypropyleneglycol (PPG) and SURFTREAT® 9173 are used as co-solvents to adjust the viscosity and to decrease the freezing point and defoamer; [0059] f) iso-Propanol, 1-octanol or pentandiol are used as alcohols to adjust the viscosity and improve compatibility.

[0060] Microemulsion based flowback aid formulations illustrating different compositional aspects of this invention are listed in Table 1. All inventive microemulsions are Winsor type IV oil-in-water emulsions.

TABLE-US-00001 TABLE 1 List of compositions for selected samples of this invention. Sample no. # 1 # 2 # 3 # 4 Water [wt.-%] 28 48 31.5 31 Caromax 20 LN [wt.-%] 12 12 0 0 Sipdril 1LV [wt.-%] 0 0 10 0 FAME [wt.-%] 0 0 0 10 Glucamide C.sub.8-14 [wt.-%] 28 28 28 25 Genapol X060 [wt.-%] 7 7 7 0 Genapol UD30 [wt.-%] 0 0 2.1 0 Genapol UD110 [wt.-%] 0 0 3.4 0 Alfonic C.sub.8-10 4.5 EO [wt.-%] 0 0 0 10 Propylene glycol [wt.-%] 0 5 3 20 iPrOH [wt.-%] 10 0 0 0 1-Octanol [wt.-%] 0 0 4 4 PEG-400 [wt.-%] 15 0 0 0 SURFTREAT 9173 [wt.-%] 0 0 16.5 0

Example 2: Effect of the Flowback Aid on the Fluid Recovery in a Proppant Pack

[0061] Sand packed columns are used to simulate fluid recovery in a proppant pack. N.sub.2 gas at a constant flow rate of 80 mL/min was used to apply pressure and displace the fluid through the column, which would mimic the reservoir gas in the field forcing the fracturing fluid through the formation and into the wellbore. A threaded standard Chromaflex® glass column 30 cm long with an internal diameter of 2.5 cm is used. Each end is supplied with two PTFE end fittings with 20 μm porosity polyethylene bed supports to prevent fines from the sand pack from plugging the line. Samples of 275 g Thor's LiteProp 20/40 mesh ceramic proppant sand (Thorsoil) are required to pack the column. 100 g samples of the base fluid with 1, 5, and 10 gptg were prepared. 70-75 g of the fluid are needed to completely saturate the proppant pack with fluid. The performance test was carried out with base fluid (7% KCl solution in water) without any flowback aid, and base fluid containing the formulations of the present invention. A lab balance was used to record the weight of the fluid collected from the sand column. Each of the concentrations has been measured 3 times and the average is reported. A test was considered complete when a minimal change in fluid recovery was observed (less than 0.2 g in 15 min).

[0062] The results are listed in Table 2 to evaluate improvement in fluid recovery with the glucamide based flowback aids (results are shown for samples 1-4). The results show higher fluid regain compared to those in the absence of additive clearly demonstrates superior performance of formulations of the present invention.

TABLE-US-00002 TABLE 2 Effect of the flowback aids on the fluid recovery in a proppant pack (regain permeability test) Flow back aid concentration Fluid Recovery Additive [gptg] [%] None 0 12.80 (potable water) 0 21.50 (3% KCl solution) Chemical A 1 30.00 (U.S. Pat. No. 7,998,911 5 38.80 B1, Example 1) 10 45.00 (comp.) Chemical B 1 28.00 (U.S. Pat. No. 8,220,546 5 43.00 B2, Sample #9) 10 79.00 (comp.) Chemical C 1 63.10 (U.S. Pat. No. 7,380,606 5 79.00 B2) 10 79.40 (comp.) Sample #1 1 79.60 5 84.20 10 86.70 Sample #2 1 72.00 5 81.00 10 83.00 Sample #3 1 75.00 5 82.10 10 85.70 Sample #4 1 76.00 5 82.20 10 84.60

[0063] An additional test has been made with the composition from Example 3 of U.S. Pat. No. 3,002,923. The composition obtained was a Winsor type II emulsion with an upper emulsion phase and a lower aqueous phase that was unsuitable for use as a flowback aid.

[0064] Chemical C according to U.S. Pat. No. 7,380,606 corresponded to inventive example 3, wherein the glucamide was replaced with the preferred surfactant taught in U.S. Pat. No. 7,380,606, col. 3, lines 3 to 5.

Example 3: Surface and Interfacial Tension Reduction

[0065] Surface tension measurements are carried out with a Krüss Tensiometer using the Du Noüy ring method. Interfacial tension measurements are carried out with a LAUDA drop volume tensiometer TVT 2 using low aromatic white spirit (LAWS) as test oil. Table 3 shows the surface tension of base fluid (7% KCl potable water solution) without any flowback aid, base fluid containing (1 gptg) of formulations in the present invention. Furthermore Table 3 shows the interfacial tension of base fluid (7% KCl potable water solution) without any flowback aid, base fluid containing (1 gptg) the formulations of the present invention against the test oil low aromatic white spirit (LAWS). The data clearly show that the glucamide based flowback aids of the present invention provide a large surface tension and interfacial tension reduction. The ability to reduce surface and interfacial tension is a key property in order to provide maximum phase trapping reduction, fast fluid return and clean up and reduce reservoir damage.

TABLE-US-00003 TABLE 3 Effect of 1 gptg of the flowback aid on surface tension and interfacial tension of LAWS in 3 wt.-% KCl solution Surface Tension Interfacial Tension Additive [mN/m] [mN/m] None 72.0 16.0 Chemical A 28.1 1.4 (U.S. Pat. No. 7,998,911 B1, Example 1) Chemical B 28.2 7.3 (U.S. Pat. No. 8,220,546 B2, Sample #9) Chemical C 28.8 2.0 (U.S. Pat. No. 7,380,606 B2) Sample #1 25.3 0.2 Sample #2 26.1 0.5 Sample #3 26.3 0.3 Sample #4 26.2 0.4

Example 4: Contact Angle Modification

[0066] Formulations appropriate for use as flowback aids need to modify wettability of solid surfaces to more water-wet. Contact angle measurements provide a good tool to investigate the ability to modify the interfacial properties between solid-liquid. Quartz has been chosen as a model surface for reservoir stone. Contact angle measurements were recorded using Krüss DSA 10 MK2 goniometer. All measurements were conducted with 20 μl drops. Contact angle measurements were taken every second for 30 s. At minimum three measurements were performed and the average of these measurements is reported.

[0067] Table 4 shows that the microemulsion based flowback aids of the present invention provide for a substantial decrease of contact angle compared to water with no additive. The ability of contact angle modification is a key parameter for providing strong capillary pressure reduction and thus removing water blocks.

TABLE-US-00004 TABLE 4 Contact angle modification on quartz surface for flowback aids in 3 wt.-% KCl solution Additive Concentration [gptg] Contact Angle None — 41 Chemical A 1 33 (U.S. Pat. No. 7,998,911 B1, 5 22 Example 1) 10 21 Chemical B 1 29 (U.S. Pat. No. 8,220,546 B2, 5 30 Sample #9) 10 29 Chemical C 1 31 (U.S. Pat. No. 7,380,606 B2) 5 25 10 24 Sample #1 1 28 5 21 10 5 Sample #2 1 37 5 28 10 16 Sample #3 1 35 5 25 10 21 Sample #4 1 31 5 24 10 18

Example 5: QCM-D Adsorption Measurements

[0068] Quartz Crystal Microbalance with Dissipation monitoring, QCM-D, is an analytical tool to characterize the formation of thin films (nm). The instrument is based on a sensor that oscillates at a specific frequency when voltage is applied. The frequency of the oscillation changes as the mass on the sensor changes.

[0069] QCM-D measurements were carried out in order to study the adsorption behavior of the microemulsion systems of this invention on surfaces. Experiments have been carried out on Silica and Alumina surfaces as models for the surfaces encountered in real reservoirs. All QCM-D measurements were performed on a Q-sense E4. Using the E4 instrument the frequency change of the sensor caused by the molecular adsorption at the sensor surface can be determined. Using the QTool software the sensor signal can then be converted into adsorbed mass and viscoelastic properties of the molecular layers which build up at the sensor surface.

[0070] The measurements were made at 22° C. using silica and alumina sensors obtained from Q-Sense. In order to get a reliable measurement, following cleaning protocol has been adopted. The silica and alumina coated quartz sensors were rinsed with excess deionized water. Then they were place in a suitable holder and placed in a 3 wt.-% Hellmanex III cleaning solution (purchased at Hellma-Analytics) and sonicated in an ultra-sound bath for 30 min. After that the crystals are rinsed with deionized water and dried with pressurized air.

[0071] Two concentrations 1 gptg and 5 gptg have been measured. Every run consist of a 2 adsorption/desorption cycles (adsorption of sample followed by washing with deionized water=1 cycle). The solution is pumped at a constant flow rate of 200 μL/min.

[0072] FIG. 1 shows that the microemulsion based flowback aid of the present invention is readily adsorbed to both tested surfaces until adsorption/desorption equilibrium is reached for a threshold of 400-500 ng/cm.sup.2. Upon flushing with water the flowback aid is completely desorbed. The data clearly show that the glucamide based flowback aids of the present invention provide the necessary surface modification upon application while no reservoir retention which is important for reduction of reservoir damage. Furthermore the complete reversibility of adsorption is a key feature leaving the reservoir rock properties unchanged after the treatment is finished to provide for maximum hydrocarbon production.

Example 6: Rheological Behavior of Formulations

[0073] During the hydraulic fracturing process high pressures are applied leading to occurrence of high shear-rates to which the fracturing fluid is exposed. This can sometimes lead to undesired change of properties or phase changes induced by high shear stress. In order to probe the behavior upon high shear rates of the microemulsion based flowback aids of the present invention the flow properties at 23° C. were measured with a rotation viscometer Haake Rheostress 6000 with cylinder geometry. 3.0 ml of sample was placed into the measurement cell and the flow behavior has been screened for shear rates between 10-1000 s.sup.−1.

[0074] FIG. 2 shows the rheological behavior of the microemulsion systems of this invention for applied shear rate between 10-1000 s.sup.−1. The flow properties of the flowback aids of this invention remain unchanged and Newtonian behavior can be observed for the whole shear rate range. This demonstrates that the microemulsion systems of this invention are stable at shear rates occurring under the high pressures applied during hydraulic fracturing processes. Also for high shear rates the microemulsion systems of this invention remain their desired properties for maximum phase trapping reduction, fast fluid return and clean up and reduction of reservoir damage.