US20100056400A1

US20100056400A1 - Use of Mineral Oils to Reduce Fluid Loss for Viscoelastic Surfactant Gelled Fluids

Info

Publication number: US20100056400A1
Application number: US12/612,867
Authority: US
Inventors: Jiang Yang; Vladimir Jovancicevic
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2005-09-15
Filing date: 2009-11-05
Publication date: 2010-03-04
Also published as: WO2009089232A2; US20080103066A1; WO2009089232A3; US7615517B2

Abstract

Fluids viscosified with viscoelastic surfactants (VESS) may have their fluid loss properties improved with at least one mineral oil which has a viscosity greater than 20 cps at ambient temperature. The mineral oil may initially be dispersed oil droplets in an internal, discontinuous phase of the fluid. In one non-limiting embodiment, the mineral oil is added to the fluid after it has been substantially gelled in an amount between about 0.2 to about 10% by volume.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional application from U.S. Ser. No. 11/970,389 filed Jan. 7, 2008, issued Nov. 10, 2009 as U.S. Pat. No. 7,615,517, which is a continuation-in-part application of U.S. patent application Ser. No. 11/517,688 filed Sep. 8, 2006, issued Mar. 25, 2008 as U.S. Pat. No. 7,347,266, which in turn claims the benefit of U.S. Provisional Application No. 60/717,307 filed Sep. 15, 2005.

TECHNICAL FIELD

The present invention relates to gelled treatment fluids used during hydrocarbon recovery operations, and more particularly relates, in one embodiment, to methods of improving the fluid loss properties of aqueous treatment fluids containing viscoelastic surfactant gelling agents used during hydrocarbon recovery operations.

TECHNICAL BACKGROUND

One of the primary applications for viscosified fluids is hydraulic fracturing. Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation. Once the crack or cracks are made, high permeability proppant, relative to the formation permeability, is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.
The development of suitable fracturing fluids is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous-based liquids that have either been gelled or foamed. When the fluids are gelled, typically a polymeric gelling agent, such as a solvatable polysaccharide, for example guar and derivatized guar polysaccharides, is used. The thickened or gelled fluid helps keep the proppants within the fluid. Gelling can be accomplished or improved by the use of crosslinking agents or crosslinkers that promote crosslinking of the polymers together, thereby increasing the viscosity of the fluid. One of the more common crosslinked polymeric fluids is borate crosslinked guar.
While polymers have been used in the past as gelling agents in fracturing fluids to carry or suspend solid particles as noted, such polymers require separate breaker compositions to be injected to reduce the viscosity. Further, such polymers tend to leave a coating on the proppant and a filter cake of dehydrated polymer on the fracture face even after the gelled fluid is broken. The coating and/or the filter cake may interfere with the functioning of the proppant. Studies have also shown that “fish-eyes” and/or “microgels” present in some polymer gelled carrier fluids will plug pore throats, leading to impaired leakoff and causing formation damage. Conventional polymers are also either cationic or anionic which present the disadvantage of likely damage to the producing formations.
Aqueous fluids gelled with viscoelastic surfactants (VESs) are also known in the art. VES-gelled fluids have been widely used as gravel-packing, frac-packing and fracturing fluids because they exhibit excellent Theological properties and are less damaging to producing formations than crosslinked polymer fluids. VES fluids are non-cake-building fluids, and thus leave no potentially damaging polymer cake residue. However, the same property that makes VES fluids less damaging tends to result in significantly higher fluid leakage into the reservoir matrix, which reduces the efficiency of the fluid especially during VES fracturing treatments. It would thus be very desirable and important to discover and use fluid loss agents for VES fracturing treatments in high permeability formations.

SUMMARY

There is provided, in one form, a method for reducing the fluid loss of aqueous fluids gelled with a viscoelastic surfactant (VES) that involves adding to an aqueous fluid substantially gelled with at least one VES at least one mineral oil fluid loss control agent in an amount that is effective to reduce the fluid loss of the gelled aqueous fluid. The mineral oil has a viscosity greater than 20 cps at ambient temperature.
In another embodiment, there is provided an aqueous fluid that includes water; at least one VES in an amount effective to increase the viscosity of the aqueous fluid; and at least one mineral oil in an amount effective to reduce the fluid loss of the gelled aqueous fluid. The mineral oil is added to the fluid after the fluid is substantially gelled. Again, the mineral oil has a viscosity greater than 20 cps at ambient temperature.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph of leakoff tests using 400 millidarcy (mD) ceramic discs at 150° F. (66° C.) and 100 psi (0.7 MPa) plotting leakoff volume as a function of time, where the base fluid is 3% KCl with 6% VES, without and with 2% mineral oil within the definitions herein; and

FIG. 2 is a graph of viscosities of aqueous fluids (3% KCl) gelled with 6% VES at 150° F. (66° C.) and 100 1/s without and with 2% mineral oil within the definitions herein.

DETAILED DESCRIPTION

It has been discovered that the addition of certain mineral oils in relatively small quantities to an aqueous fluid gelled with a VES improved the fluid loss of these brines. The fluid loss control agents herein are believed to be particularly useful in VES-gelled fluids used for well completion and/or stimulation. The VES-gelled fluids may further comprise proppants or gravel, if they are intended for use as fracturing fluids or gravel packing fluids, although such uses do not require that the fluids include proppants or gravel. It is especially useful that the removal of these fluid loss control agents may be easy and complete maintaining little or no damage to the formation. In particular, the VES-gelled aqueous fluids with these mineral oils are expected to have improved (reduced, diminished or prevented) fluid loss over a broad range of temperatures, such as from about 70 (about 21° C.) to about 400° F. (about 204° C.); alternatively up to about 350° F. (about 177° C.), and in another non-limiting embodiment up to about 300° F. (about 149° C.). In some cases suitable reservoir temperatures may be between about 100° to about 270° F. (about 37° to about 132° C.). These mineral oils may be used alone or together with other fluid loss control agents such as alkaline earth metal oxides, alkaline earth metal hydroxides, transition metal oxides, transition hydroxides, and a mixture thereof. These latter fluid loss control agents are further described in U.S. Pat. No. 7,550,143 issued Jun. 23, 2009, incorporated by reference herein in its entirety. Further, the mineral oils described herein do not noticeably change the initial viscosity of VES-gelled fluids for at least 90 minutes, which is surprising given that reservoir hydrocarbons are known to break VES-gelled fluids.
This discovery allows the VES system to have improved fluid loss to help minimize formation damage during well completion or stimulation operations. That is, the introduction of these additives to the VES-gelled aqueous system will limit and reduce the amount of VES fluid which leaks-off into the pores of a reservoir during a fracturing or frac-packing treatment, thus minimizing the formation damage that may occur by the VES fluid within the reservoir pores. Also, limiting the amount of VES fluid that leaks-off into the reservoir during a treatment will allow more fluid to remain within the fracture and thus less total fluid volume will be required for the treatment. Having less fluid leaking off and more fluid remaining within the fracture will enable greater fracture size and geometry to be generated. Thus the use of these additives in a VES-gelled aqueous system will improve the performance of the VES fluid while lowering fracturing treatment cost.
Prior art VES-gelled aqueous fluids, being non-wall-building fluids (i.e. there is no polymer or similar material build-up on the formation face to form a filter cake) that do not build a filter cake on the formation face, have viscositycontrolled fluid leakoff into the reservoir. By contrast, the methods and compositions herein use a fluid loss agent that forms small oil drops to hinder the waterbased VES fluid flow through the porous medium to reduce fluid leakoff. Surprisingly the small oil drops are very compatible with the VES micelle structures in the fluid and do not significantly reduce or impair the viscosity of VES fluid during the pumping of a treatment.
A new method has been discovered to reduce the leakoff of aqueous fluids gelled with viscoelastic surfactants (i.e. surfactants that develop viscosity in aqueous brines, including chloride brines, by formation of rod- or worm-shaped micelle structures). The improvement will permit less VES to be used since less of it will leak off into the formation. The fluid loss control agent herein may be added to the gel after batch mixing of a VES-gel treatment, or added onthe-fly after continuous mixing of a VES-gel treatment using a liquid additive metering system in one non-limiting embodiment. The high viscosity mineral oils are not solubilized in the brine, since they are inherently highly hydrophobic, but initially they are dispersed as microscopic oil droplets. The oil droplets may be understood as dispersed in the “internal phase” as a “discontinuous phase” of the brine medium/VES fluid which is the “outer phase” or “continuous phase”.
Surprisingly and unexpectedly the method employs mineral oils as a fluid loss control component. This is surprising because the literature teaches that contact of a VES-gelled fluid with hydrocarbons, such as those of the subterranean formation in a non-limiting example, essentially instantaneously reduces the viscosity of the gel or “breaks” the fluid. By “essentially instantaneously” is meant less than one-half hour. In general mineral oils are highly saturated hydrocarbons and from the literature one would expect VES-micelles to break upon contacting saturated hydrocarbons.
In one non-limiting embodiment the mineral oil is added before the VES gelling agent. In another non-limiting embodiment herein the mineral oil is added after the aqueous fluid is substantially gelled. By “substantially gelled” is meant that at least 90% of the viscosity increase has been achieved before the mineral oil is added. Of course, it is acceptable to add the mineral oil after the gel has completely formed.
Mineral oil (also known as liquid petrolatum) is a by-product in the distillation of petroleum to produce gasoline. It is a chemically inert transparent colorless oil composed mainly of linear, branched, and cyclic alkanes (paraffins) of various molecular weights, related to white petrolatum. Mineral oil is produced in very large quantities, and is thus relatively inexpensive. Mineral oil products are typically highly refined, through distillation, hydrogenation, hydrotreating, and other refining processes, to have improved properties, and the type and amount of refining varies from product to product. Highly refined mineral oil is commonly used as a lubricant and a laxative, and with added fragrance is marketed as “baby oil” in the U.S. Most mineral oil products are very inert and non-toxic, and are commonly used as baby oils and within face, body and hand lotions in the cosmetics industry. Other names for mineral oil include, but are not necessarily limited to, paraffin oil, paraffinic oil, lubricating oil, white mineral oil, and white oil.
In one non-limiting embodiment the mineral oil has a high content of isoparaffins, and is at least 99 wt % paraffinic. Because of the relatively low content of aromatic compounds, mineral oil has a better environmental profile than other oils. In general, the more refined and less aromatic the mineral oil, the better. In another non-restrictive version, the mineral oil may have a distillation temperature above about 300° C. In another non-restrictive version, the mineral oil has a dynamic viscosity of greater than about 20 cps at ambient temperature. Ambient temperature is defined herein as about 20° C. (68° F.). In an alternate, non-limiting embodiment, the kinematic viscosity of the mineral oil at 40° C. should be at least about 40 cSt. Specific examples of suitable mineral oils include, but are not necessarily limited to, PURE PERFORMANCE® 225N and 600N Base Oils available from ConocoPhillips, high viscosity ULTRA-S mineral oils from SOil Corporation, such as ULTRA-S 8, and high viscosity mineral oils from Sonneborn Refined Products, such as GLORIA®, KAYDOL®, BRITOL® 35 USP, HYDROBRITE® 200, 380, 550, 1000, and the like. The dynamic viscosity of PURE PERFORMANCE® 225N oil at 40° C. is typically 42.7 cps, and dynamic the viscosity of 600N oil is typically 114.5 cps. The use of mineral oils herein is safe, simple and economical.
In one non-limiting embodiment, other refinery distillates may potentially be used in addition to or alternatively to the mineral oils described herein, as may be hydrocarbon condensation products. Additionally, synthetic oils, such as hydrogenated polyalphaolefins, saturated fatty acids, and other synthetically derived hydrocarbons may be of utility to practice this invention.
The amount of mineral oil needed to improve the leakoff properties of a particular VES-gelled aqueous fluid is dependent upon a number of interrelated factors and is difficult to predict in advance. Typically, empirical laboratory work is helpful to determine a suitable proportion. The dynamic viscosity and/or kinematic viscosity, molecular weight distribution, and amount of impurities (such as aromatics, olefins, and the like) appear to influence the effect a particular mineral oil will have on a VES-gelled fluid at a given temperature. The effective amount of mineral oil ranges from about 0.2 to about 10% by (by volume) based on the total fluid, in another non-limiting embodiment from a lower limit of about 0.5% by. Independently the upper limit of the range may be about 3% by of the total fluid.
The use of the disclosed fluid loss control system is ideal for fluid loss reduction of VES based fracturing fluids. The fluid loss system may also be used for improving fluid loss in gravel pack fluids, acidizing or near-wellbore clean-up diverter fluids, and loss circulation pill fluids composed of VES. The fluid loss system may additionally work for foamed fluid applications (hydraulic fracturing, acidizing, and the like), where N₂or CO₂gas is used for the gas phase. This fluid loss improvement methods and compositions herein will help conserve the fluids used, and the additives therein, for these various applications.
Any suitable mixing apparatus may be used for incorporating the mineral oil fluid loss additive. In the case of batch mixing, the VES and the aqueous fluid are blended for a period of time sufficient to form a gelled or viscosified solution. The mineral oil can be added before or after the fluid is substantially gelled. The VES that is useful in the present invention can be any of the VES systems that are familiar to those in the well service industry, and may include, but are not limited to, amines, amine salts, quaternary ammonium salts, amidoamine oxides, amine oxides, mixtures thereof and the like. Suitable amines, amine salts, quaternary ammonium salts, amidoamine oxides, and other surfactants are described in U.S. Pat. Nos. 5,964,295; 5,979,555; and 6,239,183, incorporated herein by reference in their entirety.
Viscoelastic surfactants improve the fracturing (frac) fluid performance through the use of a polymer-free system. These systems, compared to polymeric based fluids, can offer improved viscosity breaking, higher sand trans-port capability, are in many cases more easily recovered after treatment than polymers, and are relatively non-damaging to the reservoir with appropriate contact with sufficient quantity of reservoir hydrocarbons, such as crude oil and condensate, or with use of internal breaking agents. The systems are also more easily mixed “on the fly” in field operations and do not require numerous coadditives in the fluid system, as do some prior systems.
The viscoelastic surfactants suitable for use in this invention include, but are not necessarily limited to, non-ionic, cationic, amphoteric, and zwitterionic surfactants. Specific examples of zwitterionic/amphoteric surfactants include, but are not necessarily limited to, dihydroxyl alkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkyl amidopropyl betaine and alkylimino mono- or di-propionates derived from certain waxes, fats and oils. Quaternary amine surfactants are typically cationic, and the betaines are typically zwitterionic. The thickening agent may be used in conjunction with an inorganic watersoluble salt or organic additive such as phthalic acid, salicylic acid or their salts.
Some non-ionic fluids are inherently less damaging to the producing formations than cationic fluid types, and are more efficacious per pound than anionic gelling agents. Amine oxide viscoelastic surfactants have the potential to offer more gelling power per pound, making it less expensive than other fluids of this type.
The amine oxide gelling agents RN⁺(R′)₂O⁻ may have the following structure (I):
where R is an alkyl or alkylamido group averaging from about 8 to 24 carbon atoms and R′ are independently alkyl groups averaging from about 1 to 6 carbon atoms. In one non-limiting embodiment, R is an alkyl or alkylamido group averaging from about 8 to 16 carbon atoms and R′ are independently alkyl groups averaging from about 2 to 3 carbon atoms. In an alternate, non-restrictive embodiment, the amidoamine oxide gelling agent is Akzo Nobel's Aromox, APA-T formulation, which should be understood as a dipropylamine oxide since both R′ groups are propyl.
Materials sold under U.S. Pat. No. 5,964,295 include CLEARFRAC™, which may also comprise greater than 10% of a glycol. One preferred VES is an amine oxide. As noted, a particularly preferred amine oxide is APA-T, sold by Baker Oil Tools as SURFRAQ™ VES. SURFRAQ is a VES liquid product that is 50% APA-T and greater than 40% propylene glycol. These viscoelastic surfactants are capable of gelling aqueous solutions to form a gelled base fluid. One excellent VES system is sold by Baker Oil Tools as DIAMONDFRAQ™. DIAMOND FRAQ™, which has assured breaking technology that overcomes reliance on external reservoir conditions in order to break, as compared with products such as CLEARFRAC™.
The methods and compositions herein also cover commonly known materials as AROMOX® APA-T manufactured by Akzo Nobel and other known viscoelastic surfactant gelling agents common to stimulation treatment of subterranean formations.
The amount of VES included in the fracturing fluid depends on at least two factors. One involves generating enough viscosity to control the rate of fluid leakoff into the pores of the fracture, and the second involves creating a viscosity high enough to keep the proppant particles suspended therein during the fluid injecting step, in the non-limiting case of a fracturing fluid. The additives herein help improve the first factor. Thus, depending on the application, the VES is added to the aqueous fluid in concentrations ranging from about 0.5 to 25% by volume, alternatively up to about 12 vol % of the total aqueous fluid (from about 5 to 120 gptg). (It will be appreciated that units of gallon per thousand gallons (gptg) are readily converted to SI units of the same value as, e.g. liters per thousand liters.) In another non-limiting embodiment, the range for the present formulations is from about 1.0 to about 6.0% by volume VES product. In an alternate, non-restrictive form, the amount of VES ranges from a lower limit of about 2 independently to an upper limit of about 10 volume %.
It is expected that the fluid loss additives described herein may be used to improve the fluid loss of a VES-gelled aqueous fluid regardless of how the VES-gelled fluid is ultimately utilized. For instance, the fluid loss compositions could be used in all VES applications including, but not limited to, VES-gelled friction reducers, VES viscosifiers for loss circulation pills, drilling fluids, fracturing fluids (including foamed fracturing fluids), gravel pack fluids, viscosifiers used as diverters in acidizing (including foam diverters), VES viscosifiers used to clean up drilling mud filter cake, remedial clean-up of fluids after a VES treatment (post-VES treatment) in regular or foamed fluid forms (i.e. the fluids may be “energized”) with the gas phase of foam being N₂or CO₂, and the like.
In order to practice the methods described herein, an aqueous fracturing fluid, as a non-limiting example, is first prepared by blending a VES into an aqueous fluid. The aqueous fluid could be, for example, water, brine, aqueous-based foams or water-alcohol mixtures. Any suitable mixing apparatus may be used for this procedure. In the case of batch mixing, the VES and the aqueous fluid are blended for a period of time sufficient to form a gelled or viscosified solution. As noted, the fluid loss additive described herein is added separately after the fluid is substantially gelled, in one non-limiting embodiment. In another non-limiting embodiment a portion or all of the fluid loss additive may be added prior to or simultaneously with the VES gelling agent.
Propping agents are typically added to the base fluid after the addition of the VES. Propping agents include, but are not limited to, for instance, quartz sand grains, glass and ceramic beads, bauxite grains, walnut shell fragments, aluminum pellets, nylon pellets, and the like. The propping agents are normally used in concentrations between about 1 to 14 pounds per gallon (120-1700 kg/m³) of fracturing fluid composition, but higher or lower concentrations may be used as the fracture design required. The base fluid can also contain other conventional additives common to the well service industry such as water wetting surfactants, non-emulsifiers and the like. As noted herein, the base fluid may also contain other conventional additives which may help improve the fluid loss characteristics of the VES fluid, and which are added for that purpose in one non-restrictive embodiment.
In a typical fracturing operation, the fracturing fluid herein may be pumped at a rate sufficient to initiate and propagate a fracture in the formation and to place propping agents into the fracture. A typical fracturing treatment would be conducted by mixing a 20.0 to 60.0 gallon/1000 gal water (60.0 liters/-1000 liters) amine oxide VES, such as SURFRAQ, in a 3% (w/v) (249 lb/1000 gal, 29.9 kg/m³) KCl solution at a pH ranging from about 6.0 to about 9.0. The fluid loss component may be added during the VES addition or more typically after the VES addition using appropriate mixing and metering equipment.
In one embodiment herein, the method is practiced in the absence of gel-forming polymers and/or gels or aqueous fluids having their viscosities enhanced by polymers. However, combination use with polymers and polymer breakers may also be of utility. For instance, polymers may also be added to the VES fluids for further fluid loss control purposes. Types of polymers that may serve as fluid loss control agents include, but are not necessarily limited to, various starches, polyvinyl acetates, polylactic acid, guar and other polysaccharides, gelatins, and the like.
The present invention will be explained in further detail in the following non-limiting Examples that are only designed to additionally illustrate the invention but not narrow the scope thereof.

General Procedure for Examples

To a blender were added tap water, the wt % and type of indicated salt, followed by the indicated vol % of viscoelastic surfactant (WG-3L—Aromox, APA-T available from Akzo Nobel). The blender was used to mix the components on a very slow speed, to prevent foaming, for about 30 minutes to viscosity the VES fluid. In the samples where mineral oil was added, the indicated amounts of ConocoPhillips PURE PERFORMANCES 225N Base Oil was used. Leakoff tests were performed using a static test method and 400md ceramic disc (0.25 inch thick and 2.5 inches in diameter) representing underground porous medium.
Measurements using a Grace 5500 rheometer at the indicated temperatures at 100 sec⁻¹were used to acquire quantitative viscosity of each sample.

Example 1

Shown in FIG. 1 are the graphs of two leakoff tests plotting leakoff volume as a function of time. The base fluid was 3% KCl with 6% VES at 150° F. (66° C.) and 100 psi (0.7 MPa), where the test was conducted with 400 millidarcy (mD) ceramic discs. It is very apparent that the fluid without any mineral oil additive leaked off rapidly, at about 15 minutes, where the fluid with 2% mineral oil within the definition herein leaked off much more slowly. The mineral oil is Pure Performances 225N Base Oils available from ConocoPhillips.

Example 2

FIG. 2 is a graph of the viscosities of aqueous fluids (3% KCl) gelled with 6% VES at 150° F. (66° C.) and 100 1/s without and with 2% mineral oil within the definition herein. It will be seen that the viscosity behavior of the two fluids over the studied time period is almost identical, which demonstrates that this small amount of mineral oil additive does not adversely affect the fluid viscosity, which is surprising since larger amounts of hydrocarbons and mineral oils tend to inhibit or break the gel of VES-gelled fluids.
As can be seen, the method of improving fluid loss characteristics described herein is simple, effective, and safe.
In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and has been demonstrated as effective in providing methods and compositions for improving the fluid loss properties of a VES fracturing fluid. However, it will be evident that various modifications and changes can be made thereto without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific combinations of viscoelastic surfactants, mineral oils, optional additional fluid loss control agent and other components falling within the claimed parameters, but not specifically identified or tried in a particular composition or fluid, are anticipated to be within the scope of this invention.
The terms “comprises” and “comprising” in the claims should be interpreted to mean including, but not limited to, the recited elements.

Claims

1. An aqueous fluid comprising:

water;

at least one viscoelastic surfactant (VES) in an amount effective to increase the viscosity of the aqueous fluid; and

from about 0.2 to about 10% by volume (by) based on the total fluid of at least one mineral oil fluid loss control agent in an amount effective to reduce the fluid loss in a subterranean reservoir of the gelled aqueous fluid, where the mineral oil fluid loss control agent is added to the fluid before, during or after the VES, and where the mineral oil fluid loss control agent has a viscosity greater than 20 cps at ambient temperature, and where the viscosity is not reduced in less than one-half hour.

2. The aqueous fluid of claim 1 where the mineral oil fluid loss control agent is at least about 99 wt % paraffin.

3. The aqueous fluid of claim 1 where the mineral oil fluid loss control agent has a distillation temperature above about 300° C.

4. An aqueous fluid comprising:

water;

from about 0.2 to about 10% by based on the total fluid of at least one mineral oil fluid loss control agent in an amount effective to reduce the fluid loss in a subterranean reservoir of the gelled aqueous fluid, where the mineral oil fluid loss control agent is added to the fluid before, during or after the VES, and where the mineral oil fluid loss control agent is at least about 99 wt % paraffin, has a distillation temperature above about 300° C. and has a viscosity greater than 20 cps at ambient temperature, and where the viscosity is not reduced in less than one-half hour.