ULTRA LOW CONCENTRATION SURFACTANT FLOODING

Abstract

A method of recovering oil from a formation that includes the use of surfactants at low concentrations. The surfactant may be an oleophilic surfactant. The method may include conditioning an oil recovery system to inhibit microbes that could consume the oleophilic surfactant. A method that determines the concentration of a surfactant that is sufficient to change the interfacial tension between oil and water in a near well bore area of an injection well in a formation but does not require changing the interfacial tension between oil and water outside the near well bore area.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to co-pending U.S. Provisional Patent Application No. 61/614,882, entitled “ULTRA LOW CONCENTRATION SURFACTANT FLOODING”, filed Mar. 23, 2012, the disclosure of which is hereby incorporated herein by reference.

BACKGROUND OF THE INVENTION

Crude oil remains an important energy source. Crude oil producers typically produce oil by drilling wells into underground oil reservoirs in a formation. For some wells, the natural pressure of the oil is sufficient to bring the oil to the surface. This is known as primary recovery. Over time, as oil is recovered by primary recovery for these wells, the natural pressure drops and becomes insufficient to bring the oil to the surface. When this happens, a large amount of crude oil may still be left in the formation. Consequently, various secondary and tertiary recovery processes may be employed to recover more oil. Secondary and tertiary recovery processes may include: pumping, water injection, natural gas reinjection, air injection, carbon dioxide injection or injection of some other gas into the reservoir.

The injection of fluids in the well is a common enhanced oil recovery method. Water is the most economical and widely used. Water flooding involves the injection of water into an oil-bearing reservoir. The injected water displaces the oil from the reservoir to a production system of one or more production wells from which the oil is recovered. Water, however, does not displace oil efficiently because water and oil are immiscible due to high interfacial tension between these two liquids.

As discussed in U.S. Pat. No. 6,828,281, entitled “Surfactant Blends for Aqueous Solutions Useful for Improving Oil Recovery,” it is generally accepted that this high interfacial tension between injected water and reservoir oil and the wettability characteristics of rock surfaces within the reservoir are factors which can negatively influence the amount of oil recovered by water flooding. One technique for increasing the oil recovery of waterflooding has been to add surfactants to the injected water so as to lower the oil/water interfacial tension and/or alter the reservoir rock's wettability characteristics. Reducing the interfacial tension in this way allows the water pressure to act on the residual oil more effectively and thereby improve the movement of the oil through channels of the reservoir. It is generally accepted that the interfacial tension between the surfactant treated water and the reservoir oil should be reduced to less than 0.1 dyne/cm for low-tension water flooding to provide effective recovery. Generally, it is assumed that adding one or more surface active agents or surfactants to the injected water forms a solution or emulsion of surfactants that sweeps through the formation and displace oil.

Currently, surfactants are designed to be miscible with water and have relatively low affinity for oil so that the surfactants can be transported deep into the reservoir and interact with the surface of the residual oil and reduce the interfacial tension over a large volume of the residual oil. To cover this large volume of residual oil requires the application of a large volume of surfactant, which makes the surfactant flooding process expensive. Further, when large volumes of surfactants are added to flood water, breakthrough may occur and cause emulsion problems in the produced oil. Breakthrough occurs when the flood water makes its way to the producing well and the residual oil is recovered in a state of emulsion with the flood water. It is difficult to separate emulsified oil into its constituent components (i.e. oil and flood water).

BRIEF SUMMARY OF THE INVENTION

One aspect of arriving at the present disclosure involved a new theory that the oil in the reservoir exists primarily as long continuous strands as opposed to the prevailing theory in the art that the oil exists in the reservoir primarily as droplets during and after water flooding. According to the new theory, long strands of oil extend from an injector well to a producer well. Further to this theory, embodiments of the invention involve changing the flow properties of the oil strands near the injector well, thereby causing this oil to be displaced, which in turn displaces oil from the affected strands towards the producer well. In other words, changing the interfacial tension between oil and flood water near the injection well area causes a chain reaction of oil flow towards the production well, though the interfacial tension between oil and flood water at locations that are not near the injection well need not be changed and in embodiments are not changed.

Embodiments of the invention include a method of recovering oil from a reservoir in a formation that includes injecting a fluid into the reservoir and injecting a surfactant into the reservoir at a predetermined concentration range of the injected fluid. In embodiments, the predetermined concentration range is based on providing sufficient surfactant to lower the interfacial tension between flood water and oil in the near well bore area but there is no requirement that the predetermined concentration range affects the interfacial tension between flood water and oil outside the near well bore area. In some embodiments, the interfacial tension between flood water and oil outside the near well bore area is not affected by the surfactant. Because only the near well bore area is effectively being treated by the surfactant, the amount of surfactant required is small compared with existing surfactant water flooding methods. In some instances, when lower concentrations of surfactant are used in the formation, the surfactant may be susceptible to premature depletion as a result of microbes within the formation consuming the surfactant. As such, embodiments of the invention involve preventing the microbes from consuming the surfactants. In embodiments of the invention, the surfactants used in the flooding process are oleophilic surfactants.

The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. The novel features which are believed to be characteristic of the invention, both as to its organization and method of operation, together with further objects and advantages will be better understood from the following description when considered in connection with the accompanying figures. It is to be expressly understood, however, that each of the figures is provided for the purpose of illustration and description only and is not intended as a definition of the limits of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:

FIG. 1 shows a diagram of a system for implementing methods according to embodiments of the invention;

FIG. 2 shows a flow chart illustrating steps according to embodiments of the invention;

FIG. 3 illustrates equipment that may be used to carry out core flood experiments according to embodiments of the invention; and

FIG. 4 shows a graph of results achieved from experiment; according to embodiments of the invention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows a diagram of a system for implementing methods according to embodiments of the invention. System 10 includes an injection well 100 and a production well 101. Oil 102 resides in oil-bearing formation 105. Oil-bearing formation 105 may be any type of geological formation and may be situated under overburden 104. Although formation 105 is shown as being onshore in FIG. 1, it should be appreciated that formation 105 may be located onshore or offshore. According to the new theory, previously mentioned, oil 102 primarily exists as strands 102-1 to 102-n within formation 105. The strands are of various lengths and may extend from injection well 100 to production well 101 as shown. In addition, the strands are 3-dimensional in nature and may cross link to other strands throughout formation 105. See E. Sunde, B.-L. Lillebø, T. Torsvik, SPE 154138, Towards a New Theory for Improved Oil Recovery from Sandstone Reservoirs, the disclosure of which is incorporated herein by reference in its entirety.

According to the new theory, oil 102 is trapped within formation 105, not as unique distinct droplets, but as strands (e.g. strands 102-1 to 102-n) in portions of formation 105's network of pores small enough to put up resistance to the surrounding drag and pressure drop of surrounding water flow. Oil 102 is continuous and present throughout the pore networks between injection well 100 and production well 101. Between the pore networks, there may be other parts of formation 105 where water flow has almost completely cleared out the oil.

In a three-dimensional system, the oil will self-organize according to the sum of pressures acting on it and the available pore network, thereby also redistributing some of its surrounding film of water. This and the fact that oil and water will seek the greatest possible separation to minimize friction, will leave the residual oil in continuous oil strands occupying pore spaces in all three dimensions. However, the general orientation of the oil strands will be parallel to the direction of flow due to the effect of shear forces.

The branched oil strands, being continuous throughout the reservoir, will not be produced because they are trapped by capillary bound water in the pore throat in regions close to the production well. As a consequence, shallow chemical treatment of production wells is often successful in releasing this trapped oil.

In current methods of surfactant water flooding, oil is recovered from a formation by pumping surfactant sufficient to treat, for example, the section of formation 105 shown as section 108. That is, current methods of surfactant water flooding seek to treat, with a surfactant, all or most areas where there is oil in the formation. This current method is based on the theory, mentioned above, that the oil exists in the formation primarily as droplets.

To be able to produce oil strands 102-1 to 102-n, the capillary bound water blocking the pore throat must be removed. This can be achieved in at least two ways. First, the water may be removed from the pore throat by reducing the capillary forces in the pore throat. Second, the water may be removed by increasing the pressure in the oil strand.

Provided a blocking pore throat has become oil-filled, the strand will easily be emptied into production well 101 because of the existing pressure gradient in the formation. This is similar to stepping on a tube of toothpaste. The water does not push the oil strand from the end, but squeeze it from all sides. This implies that water molecules are displaced on a scale of pore diameters, while the oil can move hundreds of meters in a short time span, because it flows as a continuous phase with minimal friction.

Reduction of the capillary forces around a production well has been performed using surfactants or bacteria, so-called “huff and puff”. See Lake, L. W. 1989. Enhanced Oil Recovery. Prentice-Hall Inc., Englewood Cliffs. ISBN 0-13-281601-6. A relatively small amount of surfactant (or surfactant producing bacteria) can be injected in the production well and this is then put back on production. A substantial increase in oil production can be obtained over a relatively short period using this method. The amount of oil produced by this method is observed to be much greater than the amount of residual oil the surfactant could theoretically influence. Hence the oil must have been drawn in from deep in the reservoir. This oil is often observed to have lower viscosity than the oil produced previously. This further suggests that the oil comes from areas that have not seen much water flow and consequently, has not had its lighter hydrocarbon components stripped off.

Increasing the pressure in the oil strands, (pressure pulses) can also be created by skilled application of surfactants. The pressure pulse can be obtained by applying surfactants to reduce the surface tension of the oil strand at the water injection well. Surfactants can break down surface tension to a level where the oil/water interface collapses and the oil flows out. Mathematical modeling indicates that the oil that flows out moves towards the water flow and the pressure gradient. Skælaaen, I. 2010, Mathematical Modelling of Microbial Induced Processes in Oil Reservoirs. PhD thesis, University of Bergen, Bergen, Norway (2010). A consequence of this will be the creation of a sinusoidal pressure pulse in the opposite direction into the strand. This pulse travels at the speed of sound in oil and its amplitude is increased as the strand diameter becomes smaller. At the end of the oil strand the pulse hits the water filled pore throat and the kinetic energy is converted to pressure. Although this is a relatively small force, it will add to the external pressure gradient, so that the water in the pore throat is expelled by the oil and the strand will be quickly emptied.

Consistent with the theory that oil 102 exists in formation 105 primarily as strands, embodiments of the invention change the interfacial tension between oil and water only in the near well bore area 103 of injection well 100. In embodiments of the invention, the near well bore area 103 can extend up to 50 meters from wellbore 100. FIG. 2 shows a flow chart illustrating steps according to embodiments of the invention. Method 20 includes step 201, which involves determining a specific surfactant and determining the concentration range of a surfactant that allows the surfactant to change the interfacial tension between oil and water in near well bore area 103 of injection well 100 but does not require the surfactant to affect the interfacial tension between oil and water outside near well bore area 103. In embodiments, the surfactant does not affect the interfacial tension between oil and water outside near well bore area 103. Because the surfactant is directed to changing interfacial tension in the near well bore area 103 and not to other areas, the concentration of surfactant used is low compared to traditional methods. In embodiments of the invention, the concentration of surfactant to injected water is 100 mg/L or less. In embodiments, the concentrations may be in the range of 0.1 to 100 mg/L of injected water. In embodiments, the concentrations may be in the range of 0.1 to 75 mg/L of injected water. In embodiments, the concentrations may be in the range of 0.1 to 50 mg/L of injected water. In embodiments, the concentrations may be in the range of 0.1 to 25 mg/L of injected water. Further, the traditional use of surfactants with low affinity for oil in order to treat a large area (e.g. section 107) is not necessary for the embodiments described herein. In embodiments of the invention, oleophilic surfactants that may be used as the active surfactant in the water flooding process include commercially available surfactants such as sorbitan trioleate (commercial name Span 85), sorbitan tristearate (commercial name Span 65), sorbitan monooleate (commercial name Span 80), and sorbitan monolaurate (commercial name Span 20); compounds comprising amyl alcohols, hexyl alcohols, decyl alcohols, cresols and p-nonyl phenol, and combinations thereof. The oleophilic surfactants or the concentration ranges of the oleophilic surfactants or both that may be used for water flooding may be determined by methods such as core flood experiments, simulation experiments etc. It should be noted that the core flood experiments may include experiments on core samples from the formation being considered.

The following method may be used to carry out core flood experiments. To begin, prepare a cylindrical sandstone core to resemble a reservoir in the residual situation having water and oil in representative positions. Embed a sandstone core in epoxy, evacuated to 9 torr and make water wet by saturating with brine. Determine the physical properties of the core. For example, determine the core's length, diameter, pore volume and absolute permeability. Fill the core with crude oil and then flood with brine until residual oil concentration is reached. Introduce an oil soluble surfactant such as those described herein to the core at concentrations in the range of 0.1-100 mg/L. Following surfactant introduction, set the injection pump rate to 0.1 ml/min and produced oil and water may be collected at the rate of one fraction per hour.

Once the surfactant and its concentration range have been determined at step 201, oleophilic surfactant is injected, at step 202, at the determined concentration range. At step 203, a drive fluid, such as flood water, is injected into formation 105 via injection well 100 to displace oil towards production well 101. In embodiments, formation 105 has been waterflooded to a residual oil saturation. It should be noted that the flood water, in embodiments, may be produced water. In embodiments of the invention, steps 202 and 203 may be carried out together. That is, the oleophilic surfactant may be mixed with the fluid, such as water, at the determined concentration. Alternatively or additionally, oleophilic surfactant may be injected separately from the injection of the fluid at step 203. For example, oleophilic surfactant may be injected into formation 105 via a capillary tube directly to well bore area 103 at a rate that achieves the determined concentration range, taking into account the volume of fluid injected via injection well 100. Capillary tubes for injecting oxygen, among other things, are disclosed in U.S. patent application Ser. No. 13/166,382 entitled Microbial Enhanced Oil Recovery Delivery Systems and Methods, filed Jun. 22, 2011, the disclosure of which is hereby incorporated by reference in its entirety. Similar to some of the methods in that disclosure, capillary tubes may be used to introduce oleophilic surfactants into formation 105. The capillary tubes may be made from any suitable material such as stainless steel, other metals, polymers and the like. The capillary tube can have the cross sectional area with the shape of a circle. However, the cross sectional area of the capillary tube may include any shape such as ellipse, polygon the like and combinations thereof. It should be noted that whichever method is used to inject the oleophilic surfactant, the injection may be done continuously or intermittently (i.e. in batches).

The injection of surfactant sufficient to reduce the interfacial tension between oil and water in near well bore area 103 without necessarily changing the interfacial tension within section 107, facilitates the production of oil strands 102-1 to 102-n through section 107 to production well 101. Specifically, reduction of interfacial tension between flood water and the portion of the oil strands 102-1 to 102-n in near well bore area 103 causes a pulse that is propagated within oil strands 102-1 to 102-n through the formation and moves oil strands 102-1 to 102-n through formation 105 to production well 101, from which the oil is recovered.

Under the conditions of the present invention there is no need for the use of a preflush slug nor a mobility control slug. This represents a clear advantage over existing surfactant application technologies.

Because, in embodiments of the invention, the concentration of surfactant is low, the surfactant may be consumed as substrate by microbes in the formation. Thus, it is desirable to condition the injection system and water in the near well bore area to inhibit microbes that may consume the surfactants. In embodiments, this conditioning may include reducing the microbe population in near well bore area 103. This can be accomplished either before, simultaneously with, or after step 202 and/or step 203. Various methods may be used to achieve this. These methods may be performed by exposing the microbes to biocides and biostats, either high or low pH, a particular temperature and combinations thereof. For example, a biocide may be injected into formation 105 at near well bore area 103 to kill the microbes. The capillary tubes described above for injecting the surfactant may be used to introduce the biocide into the near well bore area. Further, an initial high concentration of oleophilic surfactant may be used, which is toxic to microbes. Further yet, reducing the microbe population may include exposing the microbes to a temperature or pH that is known or predetermined to inhibit growth of the microbes or to kill the microbes.

In embodiments of the invention, injecting the surfactant directly into formation 105 allows the initial concentration of the surfactant to be high. Ultimately, however, the overall concentration of the oleophilic surfactant will be reduced as the relatively large volume of flood water is injected. In embodiments of the invention, any combination of biocide treatment, initial high concentration of oleophilic surfactant, temperature control and pH control may be used to prevent the microbes from consuming the oleophilic surfactant.

Although a method according to embodiments of the present invention has been described with reference to the steps of FIG. 2, it should be appreciated that operation of the present invention is not limited to the particular steps and/or the particular order of the steps illustrated in FIG. 2. Accordingly, alternative embodiments may provide functionality as described herein using some or all the steps shown in FIG. 2 in a sequence different than that shown. For example, in embodiments of the invention, step 204 may be eliminated because there is no issue with respect to the microbes consuming the surfactant in a particular formation. Other steps may be eliminated for other reasons. Further, in embodiments of the invention, step 203 can be performed before or simultaneously with step 202.

EXAMPLE OF CORE FLOOD EXPERIMENT THAT SUPPORTS THE PRESENT DISCLOSURE

The following core flood experiment was conducted to show the effect of low concentration surfactant flooding. FIG. 3 illustrates the equipment that was used to carry out this experiment. A rock core plug was cleaned by solvent extraction, dried to constant weight and encased in epoxy. The encased rock core plug 301 was tested with pressure and vacuum cycles to assure integrity. Encased rock core plug 301 was then saturated with a 2.5% (w/v) synthetic salt water solution under vacuum (20 g/L NaCl, 4 g/L Na₂SO₄, Sodium Bicarbonate at 1M (1:100 concentration), 1M HCl pH to 7.42, Autoclaved, Gassed with N₂). The saturation of encased rock core plug 301 is done by using pump 303 to pump synthetic salt water solution from fluid reservoir 302 into encased rock core plug 301. Digital sensor 304 measures differential pressure and back pressure valve 305 helps to maintain pressure in encased rock core plug 301. The volume required for saturation determined the pore volume within encased rock core plug 301. Additional synthetic salt water solution was injected through encased rock core plug 301 for a period greater than 24 hours, after which crude oil was injected into the core until no additional water was displaced. The oil volume and saturation in encased rock core plug 301 were calculated by mass balance of injected and recovered fluids. The rock core plug was then flooded with synthetic salt water solution and the volumes of oil and water recovered from encased rock core plug 301 were tracked. Once no additional oil had been recovered for at least one pore volume, encased rock core plug 301 was considered to be at residual oil saturation after water flood.

Encased rock core plug 301 used for this experiment was a berea sandstone with the following characteristics: 100 mD permeability, 19.8% porosity, 17.2 ml pore volume, 3.8 cm (diameter), 7.6 cm (length).

Once residual oil saturation after water flood has been achieved, a 100 mg/l solution of Span 85 (Sorbitane trioleate, CAS Number: 26266-58-0, Sigma-Aldrich) in isopropyl alcohol was prepared and a volume equal to 1 percent of the pore volume was injected into encased rock core plug 301. The outlet of encased rock core plug 301 was then monitored and additional oil production amounting to 0.37% of the original oil in place was produced from the rock core plug. FIG. 4 shows a graph of the results achieved by this experiment. The x-axis shows pore volumes after surfactant injection. The y-axis shows the percentage of original oil in place that is recovered.

It should be noted that if the concentration of the surfactant is 100 mg/l in a near well bore area then the concentration outside the near well bore area would be much lower as a result of dilution. Consequently, this low concentration of surfactant lowers the interfacial tension between flood water and oil in the near well bore area but does not affect the interfacial tension between flood water and oil outside the near well bore area.

One of the benefits of using surfactants, such as oleophilic surfactants, at low concentration is that breakthrough instances in the recovery process are avoided. That is, there is minimal surfactant present in the produced fluid to cause emulsification of oil and water emanating from the production well. Furthermore, surfactants are chemicals that can affect the properties of the oil being produced. At the low levels of concentration of surfactants used in embodiments of the invention, this chemical effect on the produced oil can be significantly minimized if not completely eliminated.

Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification. As one of ordinary skill in the art will readily appreciate from the disclosure of the present invention, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present invention. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.

Claims

1. A method of recovering oil from a formation, said method comprising:

injecting a drive fluid into said formation;

injecting an oleophilic surfactant into said formation at a concentration of 0.1 to 100 mg/l of said injected fluid; and

recovering said oil from said formation.

2. The method of claim 1 further comprising:

reducing a microbe population in said formation.

3. The method of claim 2 wherein said reduction of microbe population comprises injecting, into said formation, a selection from the list consisting of: a biocide, a biostat and combinations thereof.

4. The method of claim 2 wherein said reduction of microbe population comprises adjusting the pH of the injection fluid to inhibit microbial growth.

5. The method of claim 2 wherein said reduction of microbe population comprises exposing said microbe population to a predetermined temperature to inhibit microbial growth.

6. The method of claim 1 wherein said injection of drive fluid and said injection of oleophilic surfactant includes preparing a mixture of said drive fluid and said oleophilic surfactant and injecting said mixture via an injection well in said formation.

7. The method of claim 1 wherein said injection of fluid is done via an injection well in said formation and said injection of said oleophilic surfactant is done via a capillary tube leading from a surfactant source to the near well bore area of said injection well.

8. The method of claim 1 wherein said oleophilic surfactant is injected in batches to achieve said concentration of 0.1 to 100 mg/l over a predetermined period.

9. The method of claim 1 wherein said oleophilic surfactant is injected continuously to achieve said concentration of 0.1 to 100 mg/l.

10. The method of claim 1 wherein said oleophilic surfactant is selected from the list consisting of: sorbitan trioleate, sorbitan tristearate, sorbitan monooleate, sorbitan monolaurate, compounds comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols and p-nonyl phenol and combinations thereof.

11. The method of claim 1 wherein said fluid comprises material selected from the list consisting of: water, brine, produced water and combinations thereof.

12. The method of claim 1 wherein said recovering does not include the use of a mobility control slug.

13. The method of claim 1 wherein said recovering does not include the use of a preflush slug.

14. The method of claim 1 wherein said formation has been water flooded to a residual oil saturation.

15. A method of recovering oil from a formation, said method comprising:

injecting a drive fluid into said formation;

injecting an oleophilic surfactant into said formation at a concentration that allows said surfactant to change interfacial tension between oil and water in a near well bore area of an injection well in a formation, but does not change interfacial tension between oil and water outside said near well bore area; and

recovering said oil from said formation.

16. The method of claim 15 wherein said oleophilic surfactant is selected from the list consisting of: sorbitan trioleate, sorbitan tristearate, sorbitan monooleate, sorbitan monolaurate, compounds comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols and p-nonyl phenol and combinations thereof.

17. The method of claim 15 wherein said near well bore area is 50 meters or less from said well.

18. A method of recovering oil from a formation, said method comprising:

injecting an oleophilic surfactant into said formation,

injecting flood water into said formation, wherein said oleophilic surfactant is injected at a concentration of 0.1 to 100 mg/l of said injected flood water and wherein said injection of fluid is done via an injection well in said formation and said injection of surfactant is done via a capillary tube leading from a surfactant source to the near well bore area of said injection well;

injecting, into said formation, a selection from the list consisting of: a biocide, a biostat and combinations thereof;

recovering said oil from said formation.

19. The method of claim 18 wherein said injection of said flood water and said injection of oleophilic surfactant is done via an injection well in said formation and said recovery is via a production well in said formation.

20. The method of claim 18 wherein said oleophilic surfactant is selected from the list consisting of: sorbitan trioleate, sorbitan tristearate, sorbitan monooleate, sorbitan monolaurate, compounds comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols and p-nonyl phenol and combinations thereof.