CA2188098A1 - Control of particulate flowback in subterranean wells - Google Patents

Abstract

The addition of fibrous mixtures in intimate mixtures with particulates for fracturing and gravel packing decreases or eliminates the undesirable flowback of proppant or formation fines while stabilizing the sand pack and lowering the demand for high polymer loadings in the placement fluids. Fibers are useful for forming a porous pack in the subterranean formation. In some cases, channels or fingers of void spaces with reduced concentrations of proppant may be introduced into the proppant pack.

Description

IB5;26358~US 2 1 88~98 DA'~EOFD~ March 2, 1995 I HEP~ OE~ ~ItAJ'~H5 ~ OR FEE IS BEING
D.. ~ 1 Cv WI~H ~E UNITED ST~TES ~TAL SERVICES
I~IL ~T OFFK E TO ! ~ lL~ SERVICE
UNDER 37 CFR 1.10 ON THE D~TE INDICATED ABOVE AND
~5 ~ Dhta~:v TO THE CO' '-''~U~HER OF PATENTS AND
TW~RK~ ASHU~ON. D~ 211Za~.
~ PATENT
56312 c CONTRO_ OF PARTIC~LATF FLOWBAC~ IN
~; U ~ '~. K ~ ~ T ~ T ~ S

FT~Tn OF T~R . NVK~ lON
This invention relates to the recovery of hydrocarbons from subterranean wells. In this invention, a method, fluid, porous pack and system for controlling the transport of particulate solids back from the wellbore is provided. Fibers may be pumped downhole with proppant to form a porous pack that serves to inhibit the flow of solid~particulates from the well, while still allowing the flow of hydrocarbons at reasonable rates. Other methods allow for selective formation of voids or channels within the porous pack, that facilitating well production while filtering undesirable materials that are not to be admitted into the wellbore.

RArR~RO~N~ OF T~R lNV~-~ ~ON

- 2 1 88n~8 ., .

Transport of particulate solids during the production of oil or other fluid from a wellbore is a serious problem in the oil field.
The problem arises because in extracting oil from undérground it is necessary to facilitate a flowpath for the oil to allow the oil to reach the wellbore. The oil is then produced by allowing it to travel up the wellbore to the surface of the ground.
Transported particulate solids sometimes clog the wellbore, thereby limiting or completely stopping oil production. Such solids represent a significant wear factor in well production equipment, including the pumps and seals used in the recoveLy and pumping process.
Particles present in the pumped fluid sometimes cause excess friction and greatly increase wear on sensitive portions of the fluid handling and production equipment.
Finally, these particulate solids must be separated from the oil to render the oil commercially useful, adding even more expense and effort to the processing of oil.
Undesirable paticulate flowback materials that are transported in fluids flowing to the wellbore are particularly pronounced in unconsolidated formations.
By ~undesirable', it is meant that the flowback of the particle is undesirable. In some cases the particles flowed back may be proppant, which is desirable when in place in the formation (its intended function), but is not desirable if it flows out of the formation and up the wellbore. When that occurs, proppant particle becomes an undesirable contAminAnt because in that instance it acts to reduce, not increase, the production of oil from the well in an efficient manner.
In general, unconsolidated formations are those that are less structured, and therefore, more easily facilitate the nninhihited flow of fine particles.
Further, particulates sometimes are located in the near wellbore area for reasons that are not simply based upon natural flow to such areas. In some cases, the presence of particulates is attributed to well treatments performed by the well operator that place particulate solids into the formation or the near wellbore area.
Examples of such treatments are fracturing and gravel packlng .
Numerous different methods have been attempted in an effort to find a solution to the problem of the undesirable flow of particulates. What has been needed in the industry is a method, material, or procedure that will act to limit or eliminate flowback of particulate materials placed into the formation in a fracturing process. Until the time of this invention, there was no satisfactory method of reducing or eliminating flowback.

One method employed in the past is a method of gradually releasing fracturing pressure once the fracturing operation has been completed so that fracture closure pressure of the formation rock acting against the proppant builds gradually. In this way, the method allows proppant the matrix to stabilize before fracturing fluid flowback and well production operates to carry significant quantities of the proppant out of the fractures and back to the wellbore.
Another method that has been employed in some instances to assist in reducing flowback of particulates is the use of so-called "resin-coated proppantn, that is, particulate proppant materials having an adherent coating ho~ to the outer surface of the proppant so that the proppant particles are bonded to each other.
This process further reduces the magnitude of proppant flowback in some cases. However, there are significant limitations to the use of resin-coated proppant. For example, resin coated proppant is significantly more expensive than other proppant materials, which significantly limits it application to less economically 2~ viable wells.

Fracturing treatments may employ thousands or even millions of pounds of proppant in a single well or series of wells. Thus, the use of expensive, resin-coated proppants is generally limited by economics of well operation to only certain types of wells, or is sometimes limited to use in only the final stages of a fracturing treatment, sometimes known as the ~tailn end of the fracturing job, or simply the ~tail-in~ of proppant near the end of the pumping job.
In ll~concolidated formations, it is common to place a filtration bed of gravel in the near-wellbore area to present a physical barrier to the transport of unconsolidated formation fines with the production of wellbore fluids. Typically, such so-called Rgravel packing operations" involve the pumping and placement of a quantity of gravel and/or sand having a mesh size between lO and 60 U.S. StAn~Ard Sieve Series mesh into the unconsolidated formation adjacent to the wellbore.
It is sometimes desirable to bind the gravel particles together to form a porous matrix for passage of formation fluids while facilitating the filtering out and retAinm~nt in the well of the bulk of the unconsolidated sand and/or fines transported to the near wellbore area by the formation fluids. The gravel 21 8~098 particles may constitute a resin-coated gravel which is - either pre-cured or can be cured by an overflush of a chemical b; n~i ng agent once the gravel is in place.
In some instances, various h; n~; ng agents have been applied to the gravel particles to bind them together, forming a porous matrix.
Unfortunately, gravel packing is a costly and elaborate procedure that is to be avoided if possible.
Further, some wellbores are not stable, and thus cannot be gravel packed. Further, gravel packing does not completely ~l;m;n~te the production of fines particulates, and it is preferable to avoid the production of particulates without employing a gravel packing operation if possible. Gravel packing will not work in all instances.
Another recurring problem in pumping wellbore fluids is the enormous amounts of energy re~uired to pump fluids cont~ ng large proppant concentrations at high rates for relatively long periods of time. Large amounts of energy are needed to overcome the great frictional forces between the proppant slurry and the interior of the tubular through which the slurry is being pumped. Above a certain threshold pressure, the fluid/proppant mixture cannot be pumped at all, because of the great frictional forces present at the liquid/tubular interface on the interior surface of the tubular or wellbore. The industry needs a viable solution to the problem of excess friction during pumping of proppant. Further, the industry needs a method or fluid that will inhibit production of particles, proppant and fines without substantially adversely effecting oil recovery from the wellbore.

s~n~Y OF '~ vK~1~ON
The present invention provides a method, fluid, porous pack, and system for treating a subterranean formation. In one ~mho~im~nt, it provides for formation of a porous solid pack that inhibits the flow of both deposited proppant and natural formation particulates and fines back through the wellbore with the production of formation fluids. In the practice of this invention, it is possible to build a porous pack within the formation that is comprised of fibers and proppant in intimate mixture.
This porous pack filters out unwanted particles, proppant and fines, while still allowing production of oil. In some cases, the porous pack may be selectively fitted with voids, or finger-shaped projections, sometimes called ~hAnne1s~. Such channels are located wlthin the structure of the porous pack, and serve to provide a pPrmP~hle barrier that retards flowback of particles, but still allows production of oil at sufficiently high rates.
It has been discovered that using fibers to make a porous pack of fibers and proppant within the formation also reduces the energy consumption of equipment, and makes it possible to fracture some wells that economically could not have justified fracturing without the added benefit of reduced friction pressure. It has been found that pumping fibers with proppant provides significant reductions in the frictional forces that otherwise limit the pumping of fluids cont~;ning proppant.
Furthermore, many well treatments that otherwise were cost prohibitive because of high energy requirements, or because pumping could not proceed at a sufficiently high rate to make the procedure justifiable, are now possible. Using the present invention, the ability of the fiber mixture to reduce the friction, thereby allowing faster pumping rates, facilitates job optimization.

A well treatment fluid is shown which comprises a fluid suspension including a simultaneous mixture of a particulate material and a fibrous material. The fibrous material may be selected from a group consisting of natural and synthetic organic fibers, glass fibers, ceramic fibers, carbon fibers, inorganic fibers and metal fibers and mixtures of these fibers.
In one aspect of the invention a means for inhibiting particulate transport in subterranean wells comprises a porous pack including a particulate material having a size ranging from about lO to about lO0 U.S.
mesh ln intimate mixture with a fibrous material.
It is therefore an object of this invention to provide a means and method whereby flowback of particulate materials either pumped into a wellbore with a well treatment fluid or present as a result of unconsolidated formation fines is prevented or inhibited by the presence of fibers in an intimate mixture with a particulate material. Further, such flowback may be prevented by a porous pack, the porous pack formed by flowing back the well at a relatively high rate, or perhaps by a chemical means.
~ h~nn~l ~ may be formed in the porous pack to selectively prohibit production of undesirable '. 2188o9~ .

particles, while still allowing production of reservoir fluids, such as oil. This invention may also be used with resin coated proppants, without any fibers, to form channels in such proppant materials after they are deposited in an underground formation This is especially true.in cases for which the cost of the resin coated materials is not a significant limiting economic factor. In some instances, resin coated materials may be used only as a tail-in at the end of the fracturing job, because of the relatively high cost of such resin materials.
It is yet another object of this invention to provide a means to control the flowback of particulate materlal in subterranean fluid production without the use of complicated and expensive resin formulations. In most cases, it is believed that use of a porous pack without resin coated proppants is less expensive.

nF.~RTpTToN OF T~l2 p~ FF ~R~;!n EMBODIMENTS

In the treatment of subterranean formations, it is common to place particulate materials as a filter medium in the near wellbore area, or sometimes in fractures ext~n~;~g outward from the wellbore. In fracturing 2 1 ~8098 operations, proppant is carried into fractures created when hydraulic pressure is applied to these subterranean rock formations in amounts such that fractures are developed in the formation. Proppant suspended in a viscosified fracturing fluid is then carried out and away from the wellbore within the fractures (as the fractures are created) and extended with continued pumping. Ideally, upon release of pumping pressure, the proppant materials remain in the fractures, holding the separated rock faces in an open position forming a ~hAn~e1 for flow of formation fluids back to the wellbore.
Proppant flowback is the transport of proppant sand back into the wellbore with the production of formation fluids following fracturing. This undesirable result causes several undesirable problems: (l) undue wear on production equipment, (2) the need for separation of solids from the produced fluids and (3) occasionally also decreases the efficiency of the fracturing operation since the proppant does not remain within the fracture and may limit the size of the created flow channel.
Currently, the primary means for addressing the proppant flowback problem is to employ resin-coated 21 ~8098 -proppants, resin consolidation of the proppant or forced - closure techniques. The cost of resin-coated proppant is high, and is therefore used only as a tail-in in the last five to twenty percent of the proppant sand placement. Resin-coated proppant is not always effective since there is some difficulty in placing it uniformly within the fractures and, additionally, the resin coating can have a deleterious effect on fracture conductivity. Resin coated proppant also undesirably interacts chemically with common fracturing fluid crosslinking systems such as guar or hydroxypropyl guar with organo-metallics or borate. This interaction results in altered crosslinking and break times for the fluids thereby affecting placement. Additionally, these chemicals can dissolve the coating on the resin-coated proppant making their use ineffective.
The difficulties of using resin-coated proppants are overcome in many instances by the present invention.
Incorporating an amount of fibrous material in intimate mixture with conventional proppants solves many problems. The fibers act to bridge across constrictions and orifices in the proppant pack, and they serve to stabilize the proppant pack ~ith no or m;nimA1 effect on proppant conductivity. While this invention is not to .

be limited by theory of operation, it appears that the fibers are dispersed within the sand and, at the onset of sand production from the fracture, the fibers become concentrated into a mat or other three-~;m~n~ional framework that holds the sand in place thereby limiting further proppant flowback with the fluid production.
As used in this specification, the term ~intimate mixture n will be understood to mean a substantially uniform dispersion of components in a mixture.
Similarly, the term H simultaneous mixture" will be understood to mean that the mixture components are blended in the initial steps of the process, i.e., prior to pumping.
Fiber length, thickness, density and concentration are important variables in the success of preventing proppant flowback. In accordance with the invention, the fiber length ranges upwardly from about 2 millimeters, fiber diameter ranges of from about 3 to about 200 microns. There appears to be no upper limit on the length of the fibers employed from the standpoint of stabilization. However, practical limitations of handling, mixing, and pumping equipment currently limit the practical use length of the fibers to about lO0 millimeters. Fibrillated fibers can also be used and ~ ~ ~8098 .

the diameters of the fibrils can be significantly smaller than the aforementioned fiber diameters. The fiber level used in the proppant pack can range from 0.01% to 50~ by weight of the proppant sand. More - 5 preferably, the fiber concentration ranges from 0.1% to 5.0~ by weight of proppant.
The modulus or stiffness of the fiber appears to be important in detprm;n;ng perforr-nce. Nodulus is a measure of the resistance to deformation of a material and is a material property rather than a sample phPnnmPn~. Stiffness is a sample specific number which depends on both the material and its ~;mDncions. As a general rule, fibers with a modulus of about 70 GN/sq. m or greater are preferred. This includes materials like E-glass, S-glass, AR-glass, boron, aramids, and graphitized carbon fibers. Organic polymers other than the aramides usually have relatively lower modulus values. In order for organic polymers, such as nylon, to be useful in this application larger diameter fibers are required to provide equivalent performance to that of E-glass and stiffer materials.
In the materials listed above, E-glass is a commercially available grade of glass fibers optimized for electrical applications, S-glass is used for 2 ~ 88098 -strength applications and AR-glass has improved alkali resistance. These terms are.com.mon in the glass fiber industry and compositions of these types of glass are universally understood.
A wide range of ~;m~ncions are useful. Length and diameter have been discussed above. An aspect ratio (ratio of length to diameter) in excess of 300 is preferred. The fiber can have a variety of shapes ranging from simple round or oval cross-sectional a~eas to more complex trilobe, figure eight, star shaped, rectangular cross-sectional areas or the like.
Most commonly, straight fibers are used. Curved, crimped, spiral-~h~r~ and other three ~;m~ncional fiber geometries are useful. Likewise, the fibers may be hooked on one or both ends. They may be of a composite structure, for example a glass fiber ccated with resin to increase fiber-fiber adhesion.
The materials from which the fibers are formed is not a key variable provided that the fibers do not chemically interact with components of the well treatment fluids and are stable in the subterranean envi~ ..e~lt. Thus, the fibers may be of glass, ceramic, carbon, natural or synthetic polymers or metal filaments. Mixtures of these fibers may also be advantageously employed. Glass, carbon and synthetic polymers are preferred for their low cost and relative chemical stability. The density of the fibers used is preferably greater than one g/cm3 to avoid separation by flotation in the fluid/particulate slurry. Preferably, the fiber density is in the range of 1 to 4 grams per cc, closely mimicking the density of the particulate materials employed.

Glass fibers are particularly preferred due to their relatively low cost, easy availability and high stiffness. R~cAll~e of the fact that placement fluids and subterranean formation fluids tend to have an alkaline pH, it is most preferred to use an alkaline resistant glass (hereinafter AR-glass) having a high zirconium content. The use of more common, commercially available silica glasses is possible within the scope of this invention but, the solubility of these glasses in an alk~l;ne medium, particularly at elevated temperatures, may affect the long term stability of the fiber/proppant mixture over its lifetime in the w~l1hore.
Carbon fibers are preferred for use under harsh conditions. That is, under conditions in which the 21 8~3098 lifetime of glass fibers in the formation is limited.
This may include wells with bottom hole temperatures above about 300 degrees F., steam injection wells, wells in formations in which the connate water is not silica saturated (such as limestone formations), wells which might be expected to be treated with acid, particularly hydrofluoric acid some time after the proppant/fiber mixture is put in place, and wells which involve high or low pH or corrosive enviLo~ s.
Preferable, the carbon fibers should be at least partially graphitized, preferably more than about 90%
graphitized, and more preferable more than 95%
graphitized. The fibers may be comprised from pitch, polyacrylonitrile fibers or from novolac fibers by processes known to those familiar with the art.
Examples of commercially available carbon fibers which are useful in this process include, but are not limited ¦~ to, Donacarbo-S or Donacarbo-S S-335 from Donac Co., l~ Ltd., T-125T carbon fibers from Kreha Corp. of America, Dialead ~arbon Fibers from Mitsubishi Kasei Corp. and Panex carbon fibers from Zoltek Corporation.

A number of different proppants can be used in this - invention. Sized sand and synthetic inorganic proppants are the most c~mmon. Examples include 40/60 sized sand, 20/40 sized sand, 16~20 sized sand, 12/20 sized sand, 8/12 sized sand and similarly sized ceramic proppants such as "CARBOLITETM~ proppants.

The proppant can be resin coated sand or ceramic proppant. Resin coated sand is used in some cases as a substitute for more expensive ceramic proppants because both are cl~;m~ to be more crush resistant than sand.
The addition of fibers would aid in the control of proppant flowback or serve t~e other purposes described herein.

The combination of resin coated sand and fibers would provide a stronger pack than either system alone.
This may be useful in itself. In addition, the fibers could allow use of more highly precured resin coated proppants thereby m; ni m; zing the deleterious interaction of curable resin coated proppant with typical fracturing fluid c~mronents.

2 1 8809~

The preferred job execution practice is to mix the fibrous material throughout the entire batch of proppant to be pumped during the job. This may be accomplished by adding the fiber to the proppant before it is mlxed with the fluid, A~;ng the fiber to the fluid before it is mixed with the proppant or by A~ing a slurry of fibers at some other stage, preferably before the slurry is pumped downhole.

In certain cases, it may be preferred to pump the slurry of proppant and fiber only during a portion of the job, for example as the last 10-25% of the proppant into the fracture as a "tail-in~ to control flow back in the most economical m~nner or for other reasons. The slug could also be pumped at other stages, for example to provide an absorbed scale inhibitor to be pumped to the front of the fracture.

In certain cases, it may be desired to pump small slugs of the slurry of proppant and fiber in between slugs of slurry of proppant or to pump small slugs of a slurry of fiber between slugs of proppant slurry. This could conceivably be used to control flow dynamics down the fracture, for example by providing more plugflow-~l 88û98 like behavior. Pumping of small slugs of slurry offiber as the tail-in is one example of this general procedure.

The slurry of a mixture of proppant and fibers is useful for various reasons in the entire range of reservoir applications from fracturing to sand control.
This especially includes the newer technologies of frac-and-sand-pack and high p~r~-~hility stimulation. In these applications formation p~rmeAhilities are typically higher than those for classical fracturing, ext~n~; ng into the 10 md to 2~ darcy range. As a result, the fractures are shorter (e.g. 10-200 ft) and wider (e.g. 1/2-2 ;nches) than classical fractures. Control of flowback of proppant on these types of jobs can reduce or eliminate the need for costly hardware such as gravel pack screens in the hole and simplify job design.

The selection of fiber can be based on chemical as well as physical reasons. For example, in gravel packing and related applications where it is anticipated that the resulting pack-in-place will be treated with acid mixtures cont~;n;ng hydrofluoric acid, carbon fibers will he preferred over glass fibers when long life of the fibers is desired. Further, such treatments can provide ~hAnn~ls in the porous pack that serve to facilitate the filtering action of the proppant pack, as further described below.
The opposite may also be desired. Use of carbon fibers through the first 90% or so of the job followed by glass fibers in the tail-in would result in a pack which could be treated with solutions of hydrofluoric acid to dissolve the glass, allow flowback of a small portion of the sand at the face of the fracture and improve well productivity. Pumping alternate slugs of proppant/fiber slurries contA;n-ng the different fibers could be followed by treatment with acid to produce fracture with high permeability zones (where the glass fibers were) but with stable proppant/fiber pack zones (where the carbon fibers were) to keep the fracture open. Further, in some cases acid treatment can provide channels, or voids, in the porous pack. These voids are regions wherein the proppant is removed from the porous pack. The treatment of the porous pack may sometimes result in formation of one or more Ufingern shaped projections to traverse the porous pack.

Beyond the advantages of avoiding proppant flowback, additional advantages have been noted in the use of fibrous materials in the well treatment fluid.
First, the presence of fibers advantageously has been found to reduce the friction encountered by the fluid in the tubular, thereby saving energy and making it possible to pump jobs that otherwise would not be economical. This is described in greater detail below.
The presence of fibers in the fluid also slows the settling rate of the solid materials in the fluid thereby permitting the use of lesser amounts of polymeric gelling material in the placement fluid. This feature offers the advantages of less cost, greater retA; n~ permeAh;1;ty, a need for lower concentrations of breaker and avoidance of chemical interaction with the treatment fluid cn~ronPnts.
The fluid loss properties of the fibers are also available when fibers are incorporated into a proppant carrying fracturing fluid. In areas of high fluid loss, the fibers and sand will concentrate into a mat thereby limiting additional fluid loss in these areas.
Fibers also offer an opportunity to place well treatment chemicals in a dispersed form within the proppant pack. Thus, porous or hollow or dissolvable ;

fibers can be filled or formed with various materials such as polymer breakers, scale inhibitors, and/or paraffin and asphaltene inhibitors which can be slowly released within the pack.
The materials from which the fibers are formed is not a key variable, provided that any chemical interaction between the fibers and the comro~nts of the well treatment fluids do not dramatically decrease the ability of the fibers to perform the desired function.
In some cases, the desired function may actually require chemical interaction with well treatment fluids.
The exact mech~nip~ of the greatly reduced friction that may be achieved while pumping fibers and proppant in connection with the practice of this invention is not 1~ readily det~rm;n~hle. Nevertheless, without limiting this invention in any way, it is believed that proppant, during pumping in a fluid wihtin a tubular, generally tends to align along the center of a tubular, and that fact tends to provide a destabilized fluid flow, causing greater frictional forces. When pumped with sufficient amounts of fiber, however, the proppant/fiber mixture exhibits reduced friction, apparently because the mixture stabilizes the proppant across a larger cross-sectional area of the tubing, rather than merely along the center of the tubing. This results in formation of a lubricating thin water layer at the pipe wall surface, facilitating decreased friction pressure.
Fibers may be used to design complex flow channels in the proppant pack. For example, a fracturing job may be engineered such that voids or channels (sometimes called ~fingers~) of proppant flow out of the proppant pack after the pack is formed downhole, resulting in the creation of open channels which allow well fluids to flow into the wellbore without substantial restriction. Of course, the proppant pack still provides an effective barrier to particles, proppant or fines that otherwise would flood into the wellbore.
These fingers may range in length from about one inch to several feet, or maybe even lor.ger. They may be created in a number of ways. For example, the well can be flowed back at a rate sufficient to create channels without loss of the majority of the proppant pack. A
glass fiber proppant pack, which utilizes glass fibers, may be treated with mud acid (an aqueous solution of hydrochloric acid and hydrofluoric acid) under matrix conditions to dissolve the glass fibers within the porous pack in finger-like patterns. This may be accomplished at treating pressures less than that required to fracture the formation. When the well is allowed to flow, the proppant will be produced back from those finger-like areas which no longer contain any fibers.
This type of process, or others, results in the selective creation of a customized pack-in-place wherein the pack contains a series of concentrations of fiber/proppant mixtures. For example, the majority of the fracture could be packed with a proppant pack cont~; n; ng, for example, 1.5% fibers as a total fiber/proppant mixture by weight. During the final tail-in at the end of the fracturing job (such as during the last 1-15% of the total proppant placed in the well) the amount of fibers could be decreased such that some lower level of fiber concentration, e.g. 1% fibers could be utilized.
In general, pack stability to flow decreases with decreasing fiber concentration. In other words, the more fiber, the stronger the pack in general. Using this invention, the zone closest to the wellbore could develop open fingers while the rest of the pack r~m~i n~
stable. In another example, the majority of the pack could consist of a carbon fiber proppant pack and the tail-in could consist of a glass fiber proppant pack.
In that instance, treatment ~with mud acid or other hydrofluoric acid cont~; n; ng solution or solvent would dissolve some of the glass fibers and produce fingers in that area which will not extend into the areas cont~; n; ng carbon fibers (because carbon is not believed to be soluble in hydrofluoric acid).
In a similar m~nner~ ~h~nn~l s can be created in porous packs of resin coated proppant and fiber, or under certain conditions even without fibers. Acid treatment can L~l-~Ve the resin coating on resin coated proppant after it is in place in the formation. In that instance it is possible to decrease the flow resistance of that portion of the pack, allowing it to destabilize and proceed out of the pack, thereby allowing fingers to form. In the presence of fibers, acid treatment may be provided shortly after fracturing. With resin coated proppants, the acid treatment could occur only after the resin coated proppant has been allowed to cure properly.
The use of acid resistant fibers, such as carbon, also allows formations to be treated with acids after thé fiber/proppant pack is in place. In that instance, the acid treatments most likely could dissolve the glass fibers in a matter of minutes to hours.

The use of fibers may reduce costs in comparison to, for example, using resin coated proppants because the use of fibers does not require extended cure .imes as usually is necessary in applications using resin coated proppant. Further, fibers can be advantageously used where multizone formations with low bottom hole temperatures require a long shut in time between fracturing each formation to allow resin coated proppant to cure. The long cure times associated with such formations may be substantially avoided by using fibers, so that no shut in time is required, and several zones may be fractured in a single day. In this case, the cost saving will vary dep~n~i~g upon the number of zones to be fractured, and the required shut in times. In some cases, this will result in the ability to fracture a well in one day, rather than over a period of about one week. This is a substantial reduction, and it reduces cost and reduces shut in time for the well, which is costly in terms of lost production.
Using resin coated proppant could be accomplished by shutting in the well to cure, followed by a pumping of viscosified of fluid having a mobility ratio at downhole conditions of at least 50/l greater than the following fluid that would be injected at less than 2t 88098 -fracturing rates. This fluid could be gelled brines, but could also be a gelled oil. Following the viscosified fluid, a solution of regular mud acid contA i n; ng a mutual sol~ent such as U66 brand mud acid (U66 is believed to be a registered trademark) or butyl acetate could be applied in a strength of about 10%.
This fluid might be allowed to flow into the viscosifying fluid to react with and remove the viscosified consolidation resin within the channel or finger. The shut in time would be based on the type of resin used for consolidation It is anticipated that some resin systems would be more favorable than others for this application. The well would then be produced at a rate that would produce the now unconsolidated proppant out of the created ch~nn~l s. This cleanout process could be assisted in some cases in low pressure wells by injecting nitrogen or carbon dioxide and rapidly pumping the well back to create the conductivity enhancing channels or fingers.
In some applications, the fibrous material need not be fibers, but could be platelet type materials which increase the cohesion of the proppant in place. Such platelet materials may increase the cohesion of the proppant and m;n;mize the amount of proppant flowback when the well is produced. The platelets could be used in the full procedure of the fracturing job, or as a tail-in. In one application, the platelet materials could be mixed with gravel at the same vertical level, wherein the gravel is used in sand control. The platelets in that instance would p~ve~L the gravel placed outside the wellbore from flowing back with the produced fluids, el;m;n~ting the need for a screen in the wellbore. Platelets may be comprised of a wide variety of materials, including discs or shavings of metal, polymers, ceramics, glass, or other naturally occurring materials. Preferable, the approximate size of platelets would be larger than 0.6 mm in the longest ~im~n~iOn.
The fluids to be used in as a transport medium for the fluid suspension are not believed to be a critical factor in the practice of the invention. In general, commonly used fluids may be utilized, such as water based fluids and oil based fluids (foamed or not foamed). The preferred fluid will vary dep~n~in~ upon the particular requirements of each well.
The following examples will illustrate several formulations incorporating fibers. It will be understood that the presentation of these examples is ;

solely for the purpose of illustrating the invention and should not be considered in any way a limitation on the scope or applicability of the concept of the present invention.

21 880~

PATENT

EXANPIE 1 (CONTR0~):
The leakoff rate of a borate _~osslinked guar fracturing fluid was determined in the.following manner:
A ~racturing ~luid wa- prepared from ~ynthetic seawater conta~n1n~ 30 lb/1000 g~l o~ a poly~er ~lurry, 1.0 gal/1000 gal surfact~nt, 0.5 gal/1000 g~l bactericide and 0.25 gal/looo gal antifo~ming agent. A~oximately 2000 ~1 of thi~ fluid wa~ croJ~linked with a ~orate cro~ n~i~7 agent, ~ el into a l~rge baroid cell and heat-d to 20~ F for 30 r~n~ s~ng 1000 p~i pre~ure, a fluid 1 ~a~n~ tc~t wa~ per~ormed with a one inch cand~tone cor having _ low permeability (O.5 n~ arcy). Re~ults are pre~ented in Table A.

EXAMPLES 2--5:
In a m~nner simllar to exa~ple 1, the beha~ior o~
fiber/fracturing fluid m~ - LULe~ were determined. All test~ were performed identical to exa~ple 1 but included 2.0g of gla~ fiber~ tl/2" long and 16 microns in dl~meter) th~t were added to the ~luid prior to ~ . Other mo~f~c~tion~ to example ~ were:

EXAMPTF 2 contain~ 30 lb/1000 gal of a polymer ~lurry.

PATE~T

EXAMPLE 3 contAins 25 lb/1000 gAl of a poly~er ~lurry EXANPIE 4 W~6 prepared u~ing 2% RCl tap water, 30 lb/lOoO
gal polymer ~lurry, 1 0 g~l/1000 gal surfact~nt, O 5 gal/lOoO gal bactericide and 0 25 gal/looo gal antifoamlng agQnt No cro~ n~ W~ A~ to the ~y~tem EXANPLE 5 i~ ~dentical to EYa~ple 3 but a F-~A~tone core ha~ing A per~e~bility of 100 ~ cy Wa6 used The data are prea~t-~ in T~ble A The6e d~t~
demonstr~t- that t~ fiber~ drA~Atically decre~e the le~koff rat~ rracturing cond~tion~
TA8LE A T~FF VQT~5 AS A F~NCTION OF TIM~

1 min 0 4 ml 0 3 ml 0 6 ml 0 8 ml6 6 ml 4 ~in 1 2 ~1 0 6 ml 0 9 ml 1 0 ml7 6 ~1 9 min 2 1 ml 0 6 ~1 1 1 ml 1 7 ml8 2 ~1 16 ~ 2 9 ml 0 6 ~1 1 1 ml 2 2 ml8 8 ml 25 ~n 3 6 ~1 0 6 ~1 1 4 ml 2 7 ml9 4 ~1 36 min 4 4 ml 0 6 ml 1 5 ml 3 1 ml 0 1 2 l 8~0q8 PATENT

EXAXPIE 6: (~N ~KUL) Ihe le~koff rate o~ a part~ te o~rrying fluid was measured. The ~luid contained t~p water and 80 lb/1000 gal. of hy~ko~y~Lhylcellulose. The p~rticulate was ~
~zed c~lcium c~rbonate ~1-500 microns) which was added at ~ rtration o~ O.S lb~/gallon of fluid.
A~ tely 250 mls oS t~is f~uid was blended and added to a l~rge b~roid fluid 108e cell preheated to 17~ F.
A~ter 15 ~inutee, 500 p8i of niL~y~- pre~sure was applied to force the Sluid a~n-t a one inch sandstone-core h~ing a perme~bility of 250 n~ rcy.
RQeU1t~ ~re preeentQd in T~ble B.
~S: 7-10 The teets were repeated using gla~s f~bers ~lone and in combin~tion with thc c~lcium r~hon~te particulate material. The p~rticle loa~r~ re~ained constant at 0.5 l'b~ of ~luid. The fiber~ were ~dded to the fluid ~t the ti~e of the calcium r~rhon~te addition. The fiber wa~ q~ ~B ~ function o~ weight percent of the initi~l c~l r~l~l r~rhor~-te ~ teri~l.

EXAMPIE 6: 100% Calcium r~rhon~te; OS Fiber 2 1 8~09~
PATENT

EXAMPLE 7: 99S Calcium r~hQn~te; 1% Fi~er EXAMPl~ 8: g5% Calciu~ r~-honAte; 5% Fiber EXAMPIE ~: 90S Calciu~ r~-~Qnate; 10% Fiber EXAMPL~ 10: o% Calcium r~-~Q~ate; 100% Fiber TABLE 8 T~ FF V~T~U~-~ AS A ~uN~ ON OF TIME

TIME EX. 6 EX. 7 EX. 8 EX. 9 EX. 10 O o O o O o 1 min.110 87 76 171 3~ 2 4 ~n- 117 90 79 174 ~1 9 min.118 93 81 17S 31-1~2 16 min. 119 94 83 176 37 25 min. 118 94 83 176 37 36 mln. 118 94 83 176 38 Example 10 (fiber~ alone) ~howed no migration t nto the core. P~rt~ ate sy~te~ (Example 6) always ~how ~ome migration into the core.
The data de~on6trate Du~Lior leakoff ~.,L~ol by the fiber~. An a~dit t o~Al _avantage of fiber~ is no part~late ~igration into y.a~el p~ck or formation, therefore, le8~ damage.

The following eYample~ illu6trate the abiltty o~
f-ibrill_ted fiber6 to 6t~bilize proppant pack6:

C-5631~

EXAMPLE 11: (~UN'l'~): 200gram~ 20/40 mesh sand in 105 ml aqueou~ guar ~olution wa~ ~ourLd into a 25 mm di~meter glas~ column fitted with a bottom valve. Permea~ility o~
the pack wa~ 380 d~rciefi. The sand r~adily flowed through the 1/8 inch di~meter ~alve when it was opened.

EXA~PLE 12: In a ct~lar ~anner, the Exa~ple ll wa~
repeated but 2g polyacrylonitrile fibrillated fiber wa~
~Y~ with thc ~a~e ~lurry before it wa~ ~u~cd into the colu~n. The pack perme~h~l~ty wa~ 120 darcies. The pack did not flow out when the valve wa~ . It wa~ al~o ~table when the val~e wa~ co~plctely rsmoved leaving a 1/4 inch dia~eter hole ~ectly under the ~and pack.

Thi8 illustrate~ the ability o~ fibrillated fiber~
to consolidate a ~and pack.

EXAMPIE 13: Fibers Stabilize Sand Pack: A 30 lb/1000 g~llon ~ ~rl~nk~ guar ~olution was m~de. The composition Or this fluid was the ~ame a~ in Example 1.
Fifty ml of t~is fluid were ~ixed with 0.8 grams o~ 12mm long, 16 micron diameter glaa~ fibers. They were nixed with a ~a~llton ~e~ stirrer at low ~peed for 15 2 1 8~098 PATENT

seCon~C. 100 gramc of 20/40 ~L~ nt sand were added to the ~ixture and mixed by hand in ~ cloPed 4 oz. j~r by gentle ~h~k;~. The resulting ~ixture~was poured into a ~ertical glags column 12 mm in di~meter with ~ "T"
section at the botto~. The left end of the "TH had ~
6creen installed and the right end did not. First, water wa~ flowed down th~ colu~ and out the left side Or the ~T" to cle~n the guar fro~ the sand/fiber ~nd ~ake a p~ck. The per~e~bility of the pack wa~ then me~sured.
It was 278 darcies.
Next, the wat ~ flowed left to right across the "T".
Thi~ w~shed the ~and an~ fiber from the ~T~ section. The 6and/fiber pack in the column section remained stable.
The water ~irection wa then changed to flow down the column and out the right side of the "Tn. This created a ~ -~ re drop across the B nd/fiber pack, and no screen ~.~v~.Led the s~nd fro~ mo~ing with the flow.
The pres~ure drop W~6 increa~ed (by increasing the flow rate) until the ~and/fiber pack f~iled and flowed out of the ~ertical ~ection Or the column. The pre~sure drop acro~ the ~and/fiber pack required to do th$s was in e~ of 275 kP~ ~ 40 pBi) . Al~ost none of the sand in ;2 ~ 8~09&

PATENT

the g nd/~iber pack flowed out of the vertical section of the colu~n until the ~and pack ~failed.~

EXA~PLE 14: A 30 lb/1000 uncrOf~l tnlre~ guar ~olution was mixed with the ~.~ant ~an~ (50 ~1 solution with 100 gra~ sand) following the s~me ~.o.~ ~e as in Exa~ple 13 but w~ u~ the ~iber. Ihi~ Lu~e wa~ put into the column and the guar was cleaned out of the ~ nd pack in the ~me ranner a~ in Ex~ple 13. The per~eability of the ~and pack was 2~0 darcics. The c nd pack f~iled under an un~-a~ably low pre~sure.

These ex~mples (13 ~nd 14) ~llustr~te that mixing ribers w~th the ~o~y~.L ~and caused the formation of a ~table pack in the colu~n. The fibers held the sand in place against a such higher force (pre~sure) than t~e ~and without fibera. Al~o, the fibers had a negligible effect on the permeability o~ the sand pack.

EXAMPI~ 15: Nylon Fibers: Firty ml Or a 30 lb/1000 ~n gu~r ~olution were m~Yed with 0.2 gr~mC o~ 20mm long, 64 micron di~meter, nylon polyamide ~iber6. The ng W~ done in a ~imil~r manner to that o~ Ex~mple 21 8~09~

PATENT

13. Thi~ ~ixture w~s yOu~l into the column and tested as described in Ex~mple 13. The per~eability of the sand/fiber pack w_~ 200 d~rcie~. The ~ nd/fiber pack failed at a ~ wn pre~ure across the pack of 265 XP~.

EXAMPIE 16: S_nd pack Stah~ ation With ~igh Viscosity Fluid~: 1 gram o~ 32mm long, 16 micron diameter glass fiber wa~ ed with a ~olution o~ corn ~yrup and water haYing a ~i-co~ity o~ 600 c~ntipoi~e. The ~ixing wa~
done in a ~a~lton BQ_ch ~tirrer _t low ~peed ~or 10 ~con~. 100 gr~m 0~ 20/40 yL~ L s~nd was then ~iYed with the fibcr and colution. The mixture wa~ ~Ou~ed into the column descri~ed in Ex~mple 13. In thi~ cace, the 600 centipoise corn ~yrup ~olution w~s ~lowed through the column. The cand/fiber pack perme~bility wa5 3S2 darcie~- The ~ eD~U~e drop acros~ the ~and/fiber pack wa~ increased with the flow direction out of the right side of the ~T" (no screen). The ~ ure drop ~cross the ~and pack wa~ raised to 400 kPa without p~ck failure.
T~i~ example illustrate~ t~at the ~i~er~ c~u~e the ~nd pack to be st~ble even with hi~h ~isco~ity ~luids flowing through them. Xigh vi~co~ity ~luids ~lowing 2 1 8~09~
PATENT

through the ~and would occur if ~ gu r gel was flowed b~ck through the ~racture during clean-up.

EXAMPIE 17: scttling: A 30 lb/1000 g~ll n~ guar/borate cros~linked gel wa~ ~ade. The co~position was that of the guar solution in kxample 13. 12 ~m, 16 nicron di~meter gla~ ~ibcr~ (0.8 weight % of sand) ~nd 20/40 ~L u~ nt ~and were added to a gu~ntity of the gel such that thc sand concentration was 10 lb/gallon of gel. The ~and and ~iber werc added to the guar solution prior ~he gel cross~t n~r solution. The fiber wa~ added to the ~olution, and ~i~pereed w~th a Hamilton ~e~ch ~ixer.
Thi~ w~s added to the ~and in a clo~ed ~ar and gently ~t ~ed by ~h~t ~g. The compo~ition Or the cro~linker ~olution was 0.3 gra~ boric acid, 0.6 grams ~odium .~d~o~ide, 1.2 grams codiu~ glucon~te, 0.~ ~1 trieth nol amine, and 0.6 gr~ms ~odiu~ thio~ulfate for 500 ml of guar ~olution. The re~ulting ~ixture was placed in a heated clo~ed column ~nd further ~ixed ~y in~erting the 2~ colunn once per ~nute. The mixture wa~ heating to 66 dc~ L__ Cel~u~ ~nd thc column wa~ oriented in the vertical. The m~LuL~ ran to the bottom of the column.
The settling of the sand and ~iber in the guar gel were 0 9 ~
PAT~
C-~6312 ob~erved a~ ~ function of time at 66 degrees Ce~sius Pe~ ettling w~ c~lcul~ted ~ follows ~ settling - 100 X (tot~l height-~nd h~ght)/~xlmu~
liquid h - ~ ~ht.
Tot~l height i~ the h~ht o~ ~and plu~ gel liguid Sand h~ ~t i8 t_~ h~~ ~ht 0~ the top o~ the ~ nd l~yer ~Axi~U~ ~ height i~ determined with ~and ~nd w~ter in the ~me~ ~mount~

After 315 ~nute~ the ~ettling for the sand and ~ib~r W~8 17% There w~ no t-n~-n~y o~ the sand and riber~ to ph~se eep~r~te during the ~ettling EXANPLE ~8 The ~xperinent of Ex~mple 17 was repe~ted with 1 3% o~ the gl~ fiber ha~ on the ~and we~ght In this c~e, ~fter 260 ~inute6 the settling wa6 14%

EXANPIE 19 T~e ~and ~lone in the fluid o~ Ex~mple 17 ~ettled 60% in 300 minuteC By comp~rison with Example~
17 ~nd 18, thi8 ex~mple ~how6 th~t the gla~s ~iber~
reduce the ~ettling r~te of the s~nd in the gel ~? I 8~0~8 PATEN~

EXANPLE 20: Interaction with Borate Gel: Six liters of a 30 ~ OOo gallon ~.~LC~ n~ guar ~olution were mixed with 47.6 gra~ oi 12 mm long, 16 micron diameter glass fihers. Th- fiher level wac har~~ on 8 lb/gallon 6~nd lo~ n~. No s~nd was added to the fiber/601ution ~ixture. The fiber/so~ution mlxture was allowed to sit a~lo~imatcly one halr hour ~fter ~ixing. Two fifty ~1 6ample~ wer- r-~ov-d. Thc fibe~ were filtered rrom one Or the fifty ~1 ~pl-s. Thc Fann35 viccosity Or each sample was ~ea~ured at 70 degrees F. The sample ~i~
ribcrs had ~iscocities Or 51 and 30 cp. ~t 170 ~nd S10 sec~l r~te re~pectively. The filtered s~mple had - ~iccosities Or 42 ~n~ 24 cp respectively. The visco~itie~ Or the ~iltered ~ample were well within 6pect~0~t~0ns for this gu~r solution. The ~olution with fibers had a slightly h~ r ~i~cosity.

Next bor~te cro~Cl~n~r solution (composition in Ex~mple 17) W~6 added to both solutions. The time to g~ n~ wa~ nsa~ured for both by ~h~ng lip~ method~. The filtered ~olution had a ~hang lip~ time Or 4 minutes, 44 -e.-Qn~. The ~ Q le with ~iber had ~ ~hang lip~ ti~e of 2 ~ 8~9~
PATENT

4 ~inutes 27 -~oon~ . Both these cross1inking times are within specification~ for the~e guar gelc.

This ~x~mple illufitrates t_at the preferred glass fiber~ do not afrect t_e ~isco~ity and the "hang lip" gel tines of the borate croc-l~ n~ guar gel. This illu~trates th~t the glas6 fibers ~o not affect the guar gel chemi~try or ~isco~ity ~ ~n~ ficantly.

EXAMPI~ 21: Interaction With Zirconate Gel: The s~me mixing ~o~ o as in Example 20 was followed with a 50 lb/1000 gallon L~dk~ 1 gu~r solution. The 12 ~m glass ribers wcre added to, then riltered out o~ one aliquot o~ the solution. Thi~ aliquot and another aliquot t~at had not been expoQed to the fibers were CrOB~l ~ n~ with a 4.5 lb/1000 gallon zirconium solution.
The solution was 4~% zirconium crosslinker, 24S high te~pet~Lule stab~l~ 7er ~ and 36% w~ter. Crossl~ n~ ~g hang lip time~ were 9:19 ~inutes for the s~mple not ~x~_-ed to the fiber~, and 10:13 minute~ for the ~mple ~YpOFr~ to the ~iberG. Again, the ~ibers do not affect the cro~l ~nlr~ gel che~iE~try.

2 1 8~09~3 PATENT

EXANPIF 22: ron~ti~ity. ron~ti~ity ~esting was done with 20/40 mesh ~ G~ant. The fluid was a 30 lb/lOOo gallon uncros~linked guar ~olution. Th~ co~pos~tion was 17ml of 2% ~Cl water, 0.12 ~1 guar ~lurry, 0.02ml S fluoroo~rh~n ~urfact~nt, ~nd 0.005ml defoamer. The fluid was mixed with 63 gr~m~ o~ 20/40 ~ ~nt. The test was done in ~ n~ti~ity cell at 25~ F and 5000 psi clo~ure DL~ . The ~ tivity after 23 hours of ~lowback was 157 d~rcie~.
The te~t WaB repeated with the same guantities of fluid and ~ nt. In addition, 0.5 qr~R (0.8%) o~ 12 mm long, 16 ~icron di~eter ql~Rs fiber~ were ~ixed with the propp~nt ~nd ~ . Th~ CQ~ ~ti~ity ~fter 24 hour~
o~ ~1fwLack ~as 153 darcies.
Thi~ ex~pl~ illustr~te~ that the fibers have a negligible effect on ~L~ant pack permeability.

EXAMP~E 23: Slot Flow. The fiber/6and p~ck st~ility wa~ ts~ted in ~ ~lot geometry. 5 liter6 o~ 30 lb/1000 g~llon ~ sltn~A guAr ~olution were m~de (34 ml gu~r ~lurry, 5 ~1 surract~nt, ~nd 1.25 ml defo~mer and 5000 nl of tap water). ThiB wa~ mixed by recircul~ting the ~luid through ~ holding t~nk and centrifuge pump for 2 1 8~3~8 PATENT

15 ~inutes. 5000 gr~ms of 20/40 ~ nd was then added ~nd allowed to disper~e for ~.oximately 1 ~inute. ~0 g ~ms of 12 ~ long, 16 micron di~meter gla~s fiber were added to the mixture. The re~ultiNg ~lurry was pumped into the slot.
The slot i8 ~ x~ately 5-1/2 feet long, 1/4~ wide and 6" hig~. The ~urface- are ~mooth, with the ~ront ~urfaoe being clear to ~llow ob~ervation. A screen w~
pl~r-~ over the ~xlt port ~o th~t the ~and could not flow out of the ~lot. The 81urry was pumped into the ~lot fron the other en~. In thi~ g~ometry, a pack of ~and and fiber~ built up agatn t the ~creen, while the fluid was ~llowed to flow through the ~crsen to ~ hnl~n~ tank. A
6" long sand/fiber pack W~6 built up again t the screen.
The gu~r fluid wa~ then W~h~ from the p~ck wit~
water. The acreen wa~ removed from the end o~ the slot, le~ing the pack with ~n open 1/4~ x 6~ ~ace. W~ter was flowed through the p~ck to te~t it~ DL~-yLh. The w~ter flow was incre~sed until ~ 6 pci ~ -~ure drop w~s ~ LQd by the p~ck. At this point the p~ck beg~n to fail ~nd ~nd flowed out of the ~lot.

PAT~NT

EXAMPLE 24 Slot Flow, Rough wall~, Glass fi~ers The same ~lurry a~ in Example 23 wa~ again tested in the 510 geo~etry In thi~ exa~ple, the w~ of the slot were ro~ghPn~d Thi~ was done by ~d~ering ~ layer of 20~40 ~and to the wall~ of the ~lot with rubber cement In thi~ geo~etry, ~ 22~ ~ny fiber p~ck w~ obt~in~ and the ~L ~ yUh o~ t~e p~ck e~ e~ 15 p~i drawdown (upper l~mit on pump) EXAMP~ 25 Slot Wlth Gas Flow A si~il~r ~lurry as used in EY~mple 23 w~ uJed in thi~ ex~mple In thi~
eY~mple we u-ed ~ 10 ~b/1000 g~llon gu~r ~olut~on Thi~
~lurry wAc pu~ped into the elot with rough wall~ and the s~reen a- de~cribed in ~Ya~ple 24 The guar solution wa~
wa~hed from the ~~nd/~iber pack with water Then the pack WA~ dried with ais ~lowing through ~t for 3-1/2 hours The ~creen was removed and the te~t for p~ck L ~ ~y Lh was performed The p~ck length was lB n . ~he ~ir Slow rate was increased to 13 p~i drawdown acrosc the pack The pack did not fail The pack was then ~urther dried at low _ir ~low rate for an a~tttn~Al two hours The test was repeated The 2 1 8~098 PATENT
C-~6312 sand/fiber pack did not fail with flow up to an 11 psi drawdown ~cro~s the pack.
This examplc illu-trate~ that the sand/~iber paok is re~i~tant to ga~ flow~ ~8 well as w~ter ~low~.
S
EXAN~IE 26: Slot Flow With 1/2 n ar~ide fibers:
~EVLARTM poly~r~mide ~berc were tested in th- clot geometry wit~ rough walls. The fluid was a 20 lb/1000 gallon uncro~sl tn~ gu~r ~olution similar to Exa~ple 23.
The ar~m$de ~ibers were 12 ~m long ~nd 12 ~icrons in diameter. The slurry ~ixture was 4 llters of ~luid, 4 kg o~ 20/40 ~.~.L 8~n~, _nd 12 gr_ms o~"KE~AR' riber (0.3 wt. % of sand)-The sand/~iber ~lurry was pum2ed into the rough w~lled ~lot with the screen at one end a~ was de6cribed ~n Ex~ple~ 23 and 24. The re~ulting ~and pack was 14.5~
long. The fluid was wa~hed rrom the sand fiber p~ck w~th wAter. The ~ _~. was removed and the water wa6 agzin ~lowed th~v~yL the pack. The pack beg~n to fail at 3 ps~
~ wn.

EXA~}IE 27: Slot Flow, 1~ Nylon Fiber~: We te~ted 1 long nylon fi~er~ in the rough walled ~lot. The fiber~

2 1 ~9~
PATENT
~-~6312 were 64 mlcron6 in diameter. The ~lurry was 5 liters of 30 lb/1000 gallon uncro~ClinkD~ guar ~olution, 5 Rg of 20/40 ~L~ant ~and, ~nd ~5 yramfi of nylon fiber. The ~and/fiber p ck length wac 6~. The pack began to fail at le6~ than 1 p~i d.~w~wn.

Example~ 23-27 illustrate that ~iber~ 6tabilize a ~,u~nt p~ck in a ~racturing geometry even with 6~00th wall~ an~ no clocur~ ~tr~

EXANPIE 28: ~lot Flow: The fib ~ ~and pack DLL~yLh was te6tod. A 30 lb/1000 g~ uncro~ n~ gu~r solution with the same composltion as RY~mrle 23 e~c~L that 2S
RCl water wa8 u~ed. 20/40 ~ant was added to the fluid at 12 poundc per gallon. 12 ~m long, 16 micron diameter glass fiber~ were al80 A~D~ at lS o~ the ~o~ant lovel.
The clurry wa~ loAded into a 5-1/4 n by 5-1/4~ by 1/4~ ~lot. The walls of the slot were lined wlth Springwall ~_ndstone. A clo~ure Dl ~er- o~ 250pri was ~pplied. The cell wa~ heated to 21~ ~. The fluid wa~
washed from thQ gel with a 1% RCl ~olution flowing at a slow rate (50ml/mln). The brine was then w s~ed ~rom the 2 ? 8809~
PATENT

cell with a saturated niL.G~e.. gas flow. The cell was then heAted to 22~ F. The test wa~ no performed with the nitrogen flow at incr~ar~n~ drawdown across the pack.
The pack w~ ~tablc at 20 p~$/ft. with a closure stress ranging from 100 to 200 psi.

EXANPLE 29: Slot Flow, NO FIBER~: The ~ame experi~ent as in Example 28 wac performed with ~yant without fibers.
At 250 p8i clo~urc .LL~r, 1/4~ ~lot, 22~ F, the y~y~ant lo pack fa$1ed at le~ than 0.2 psi/ft.

~ -~ e~mple~ demonstrate the ab~lity of fiber~ to 6tabilize a ~.~yant pack under representative downhole conditions.
EXANPI~ 30: Yard Test: The glass fibers were tested in a yard te~t. The 12 mm long, 16 micron diameter glass fiber~ were A~A~ at a 1% level to the s~nd in a simulated ~racture ~ob. The fiber~ were ~P~ by hand into a fracturing fluid blcnder with the 20/40 proppant.
T~i~ ~ixture wa~ combined with the 30 lb/1000 g~llon cro~ racturing fluid in the blender. It then flowed tl~ouyh a triplex pump, a tree savex, a vaxiable 2 1 ~09~
PATE~T

choke with 1000 p~i drawdown, and 300 y~rds of 3 inch pipe.
The pumping ~chedule was:
1 ppg ~ ~ant at 6bbl-/~in.
1.5 ppg ~L~fV-~L at 6 bblc/~in.
2 ppg ~ nt at 6 bbl-/~in.

3 ppg ~ .ant ~t 8 bbl~/~in.

4 ppg ~ nt at 8 b~ n.
1o S~mple~ of the ~ixture wcre taken at the exit of the pipe. The glas~ fiber- were well ~ixed with the propp~nt ~nd fluid, ~l~h~h ~omc ~lber br~ ge was apparent.

The -~A~ple ~e~on~tr~te~ that fiber/~and ~lurrie~
can be pu~ped wlth ~G~v~ o~Al pumping eguip~ent and th~t the fiber~ are ~t~ble ~uyh to survive thi~
treatment EXAMPIE 31 Pe~ Lion pA~t~ The ~bility of riber~
to keep sand in a re~ervoir over a 1/4~ perforation was tested A ~odel perfor~tion 1/4~ in diameter and 3~ long with a 75 cubic inch re~-rvoir at the outlet wa~ used for th~ te6t~ The reservoir wa~ eguipped with a 20 me~h ~creen at the oth ~ side from the perforation Slurry ~o 11~ then flow into the reservoir tLL~yL the perfor~tion ~nd out thl~yh the ~creen ~ 5 ~ of ~ 20 2 i 8~09~
PAT~

lbm/1000 gal/h~o~Lhyl cellulo~e tREC) solu~ion was prepared (135 g Ng4Cl (3 wt%), 28 3 m~ HEC olution and dry caustic to rai~e the p~ to 8) Thic w~s ~ixed by recirculating th- fluid Lhl~uyL a holding tank and ~e L.ifuge pump The fluid wa~ L~aLed for ca 30 min 13 5 g ArA~ide ~tapl-, V2~ long, wac ~lxed in and 2,696 5 g 20/40 ~and were adaed to the ~Yture (~ l~n/gal ~ant, 0 5 wt% ~iber b~ed on the ~L~ nt) The resulting 81urry wac pu~ped into the reser~oir LL~vuyL
the 1/4" perforat~on A pack Or ~and and ~iber~ ~uilt up againct the ccr en, whlle the ~ wa~ allowed to flow through the ~ e~ into the h~ n~ tank.
After p~r~ n~ the perfor~ation, the line~, the holding tank ana the pu~p were cleaned and f~lled with water. The flow ~rection wa~ .~v~ed and water wa~
pu~pcd from the ~creen side tL~uyL the packed perforation. No ~ nt W~B ~ 1 through the 1/4~
hole even by increasing the flow rate till a pre~6ure drop across the pack of 15 p~i was re~h~ and kept for sevcral ~inutefi. The water flow wa~ turned off and on se~eral time~. That did not pro~uce s~nd either.

2 1 8~098 PATENT

EXAMPIE 32: The ~ame perforaetion was pA~ with 20/40 ~and and 12 mm long, 16 micron diameter gl~s~ fiber using ~a 30 lbm/looo gallon uncro~-ltn~ guar solution. 4.5 L
fluid were prep~red (90 g RCl (2 wtS), 4.5 ~L surractant, 1.125 ~ defoamer, 30.6 m~ guar ~lurry) ~nd hydrated for 30 ~in. 27 g gl~s fiber w re ~ nd ~fter one minute 2,700 g 20/40 ~,~.L (5 lhm~gal~ 1 wt% fiber based on ~ant). The p~ck~ n~ and w~ter flow were done as in EY~P1e 3 1 .
T~e p~cked perfor~tion w~ kept for 10 daya. Wi~hin t~i~ time w~ter W~8 flown through it c~. 5 times, each time turnlng the pump on _nd off ~ever~l timea. The pack wa~ ~table ~nd pr~An~ - ~ one tea~poon ~ o~ant at ~he mo~t.
EXAMPLE 33: The ~me ~etup a~ in Exa~ple 31 except for a 1/2~ peYrv~Lion. Thi~ time pol~o~ylene fiber~ (1/2"
long, 4 ~ r) ~nd 30 l~m/1000 gal HEC were used.
Fluid: 4.5 ~. 135 g N~4Cl, 42.5 ~L HEC ~olution, caustic to rai~e the p~ to 8.
~ nt: 2,696.5 g 20/40 ~and (5 lbm/gal) Fiber: 27 g poly~lv~ylene, 1/2~ long, 4 denier (1 wt%
- based on ~L~p~.L) ., Packing and flowing water through the above worked well, and no sand production was encountered even over 1/2~ hole.
Examples 31 through 33 illustrate that different types of fibers may be used to hold sand in place in the formation beyond the perforation tunnels. This is applicable to gravel packing, where gravel is placed outside of the perforations to stabilize subterranean formation sands.
EXAMPLE 34: Stabilization of Different Types of Proppant: Column experiments were performed using the fluid c~mro~ition (30 lbilO00 gallon guar solution), and procedure as in Example 13. 50 ml aliquots of fluid were mixed with 100 grams each of various proppants and 1 gram (or 1.6 grams) each of 12 mm long, 16b micron diameter glass fibers. The proppants were 20/40 "CARBOLITETM , 20/40 ~ACFRAC SB ULTRATM curable resin coated sand, and 20/40 ~ISOPACTM light weight gravel.
The ~CARBOLITE n proppant has approximately the same density as sand, but is more spherical. The "SB ULTRA"
has a~o~Lmately the same density and sphericity as sand,.but has a polymer coating. The n ISOPAC"

lightweight gravel is much less dense than sand, is more spherical, and has a polymer coating.

The results of the column tests are shown in Table S C -.

TABLE C. Strengths of Various Glass Fiber/Proppant - Packs Fiber Level CARBOLITE SB ULTRA ISOPAC
St. % sand 1% >2 5 kPa >250 kPa 55 kPa l.6% >2 0 kPa >250 kPa Examples 13 and 34 illustrate that the coating and sphericity of the proppant do not affect the ability of the fiber to strengthen the pack. Low density proppants ("ISOPAC") may require greater amounts of fiber for pack strength.

EXAMPLE 35: The procedure of Example 31 was repeated except that the pack was made in such a way that the half of the perforation model closest to the perforation hole was filled with an identical sandtfiber mixture - while the back half of the perforation was filed with sand. The pack was tested in the same way. No sand was produced.

Packing and flowing water through the above worked well, and no sand production was encountered even over 1~2~ hole.
Examples 31 through 33 illustrate that different types of fibers may be used to hold sand in place in the formation beyond the perforation tunnels. This is applicable to gravel packing, where gravel is placed outside of the perforations to stabilize subterranean formation sands.

EXAMPLE 34: Stabilization of Different Types of Proppant: Column experiments were performed using the fluid composition (30 lb/1000 gallon guar solution), and procedure as in Example 13. 50 ml aliquots of fluid were mixed with 100 grams each of various proppants and 1 gram tor 1.6 grams) each of 12 mm long, 16b micron diameter glass fibers. The proppants were 20/40 "CARBOLITETM , 20/40 ~ACFRAC SB ULTRATM curable resin coated sand, and 20/40 "ISOPACTM light weight gravel.
The "CARBOLITE~ proppant has approximately the same density as sand, but is more spherical. The n SB ULTRA"
has a w~oximately the same density and sphericity as sand, but has a polymer coating. The n ISOPAC"

'' lightweight gravel is much less dense than sand, is more spherical, and has a polymer coating.

The results of the column tests are shown in Table C. -TABLE C. Strengths of Various Glass Fiber/ProppantPacks Fiber Level CARBOLITE SB ULTRA ISOPAC
St. % sand 1% >225 kPa ~250 kPa 55 kPa l.6% >250 kPa >250 kPa Examples 13 and 34 illustrate that the coating and sphericity of the pro~p~nt do not affect the ability of the fiber to strengthen the pack. Low density proppants ("ISOPAC") may require greater amounts of fiber for pack strength.

EXAMPLE 35: The procedure of Example 31 was repeated except that the pack was made in such a way that the half of the perforation model closest to the perforation hole was filled with an identical sand/fiber mixture while the back half of the perforation was filed with sand. The pack was tested in the same way. No sand was produced.

':

Example 35 demonstrates that the proppant/fiber slurry may be used as a tail-in during the final stages of the procedure, or may be pumped in stages between slugs of proppant slurry.
S ' ..
EXAMPLE 36: Proppanttfiber pack strength tests were performed in a rectangular cell with inside ~;m~ncions of 12.7 cm long, 3.8 cm wide, and 2.5 cm thick. The cell was open at both ends. A perforation type geometry was set up in the cell by creating a restriction 0.63 cm..
on all inside dimensions. T~e cell was set up with a screen at the outlet. A slurry contAin;ng 500 ml of 30 lb/1000 gallon guar solution in water (composition in Example 1), 500 grams or 20/40 sand, and water (composition in Example 1), 500 grams of 20/40 sand, and 1.25 grams of 7 micron by 0.63 cm carbon fiber was pumped into the cell and formed a pack against the exit screen. The guar was washed from the pack and then the screen was removed from the exit port. A closure stress of 500 psi was applied to the face of the pack. Water was flowed from the inlet to outlet through the length of the pack. The proppant and carbon fiber pack resisted the flow of water up to 35 kPa ~about 5 psi) before the pack filed and flowed through the restriction.' EXAMPLE 37: The same test as above was performe by 5 grams of AR grade glass fibers (20 micron diameter, 1.27 cm long) were added to the sand and carbon fiber slurry.
The resulting pack held a drawdown of 135 kPa (about 18 psi) without failing.

10 EXAMPLE 38: The same test as above was performed with a slurry of 500 ml 30 lb/1000 gallon guar solution, 500 grams 20/40 sand, and 5 grams AR grade glass fibers (20 micron diameter, 1.27 cm long). The pack failed at a drawdown of 36 kPa (5 psi).
EXAMPLE 39: The same test as above was performed with a slurry of S00 ml 30 lb/1000 gallon guar solution, and 50 grams 20/40 sand without fiber added. The pack failed ;mme~;ately with the onset of water flow, and no measurable pressure drop was.maintained across the pack.

EXAMPLES 36 - 39 show that carbon fibers can be used to stabilize the pack and that mixtures of fiber can result in stronger packs than a single fiber type.

- EXAMPLE 40: Proppant fiber pack strength tests were performed in a disk shaped cell. The diameter of the disk is 15.2 cm, and the thickness is 1.2+/-0.05 cm.
the cell has inlet and output openings 10.2 cm across.
A screen was placed across the outlet. A slurry cont~; n;ng 1000 ml of S0 lb/ 1000 gallon guar solution, 1000 grams of proppant, 15 grams of AR glass fibers (20 micron diameter, 12.7 mm long) was pumped into the cell and formed a pack against the screen. In each test the proppant size was varied. The guar was w-~he~ from the pack, and then the screen was L~..ov~d. Closure stress of 1000 psi was applied to the faces of the disk. The excess pack was cleaned from the cell, so that the pack was perpendicular to the flow direction from inlet and outlet. This resulted in a pack length from inlet to outlet of 11.4 cm. Water was then flowed through the pack until it failed and proppant flowed out of the cell. This coincided with a relaxation of the closure 20 stress.
PROPPANT PACK STRENGTH
20/40 60 kPa (8.5 psi) 12/20 21 kPa (3 psi) 16/30 21 kPa (3 psi) The same procedure was followed as in example 40 except that no fiber was added to the 20/40 sand pack.
The pack failed at the onset of water follow and no pressure drawdown was maintA;ne~.
The results show that the fibers will strengthen different proppant sizes.

EXAMPLE 41: 500 ml of a 50 pound per 1000 gallon borate crosslinked guar gel were prepared. The gel contained 3 grams guar, 10 grams potassium chloride 0.5 ml surfactant, 0.25 ml bactericide, 0.125 ml antifoam agent, 0.5 ml stabilizer (iron control), 0.6 grams oxygen scavenger, 0.6 grams boric acid, 1.5 grams sodium hydroxide, and 3 grams sodium gluconate. 500 grams of 20/40 US mesh brady sand and 7.5 grams AR grade glass fiber (20 microns diameter, 12.7 mm length) were mixed into the gel.

The resulting slurry was poured into a metal tube 22.1 mm inside diameter, and 127 mm in length. The ends of the tube were capped, and it was then heated to 150~C
for 24 hours. These conditions were sufficient to "break~ the gel. The tube was cooled, opened and a 2 t 88098 washer with 12.7 mm hole was fitted into one end of the tube. The tube was connected to a water source such that the washer was at the outlet end of the tube.
Effectively the slurry mixture was held from sliding out of the tube by the washer, but water could flow through the slurry sand pack.

The water flow was initiated at a low flow rate to wash the broken gel from the sand pack. No sand flowed out the tube with the water. The water flow rate was then increased. No sand flowed until the flow rate reAche~ 7.6 L/min. which correcron~ to 381 kPa drawdown across the pack. At this point the sand pack failed and ran out of the tubing through the washer.
EXAMPLE 42: The same experiment as abG~e was run with the crosslinked gel and sand, but without the AR glass fibers. The sand pack flowed out of the tube through the washer at very low flow rate during the cle~ning of the broken gel from the pack.

EXAMPLE 43: ~
This example shows that the use of fibers may reduce treating pressures. During a fracturing 2~ ~8~98 treatment in southern Texas, concentration of 20/40 ceramic proppant was ramped up from 0 to 2 to 4 to 6 to 8 pounds proppant added (ppa) per gallon of fluid.
Shortly after initiation of the 8 ppa stage the treating pressure increased from 5800 psi to more than 7500 psi.
Then, 1.5% fiber was added to the slurry. The treating pressure rapidly decreased back to 5800 psi. After some time, fiber addition was stopped. Treating pressure ;mme~;ately began to increase. When the pressure reached 6500 psi, addition of fibers was resumed, this time at 1% by weight of propp~nt. Treating pressures again declined to 5500 psi. This example demonstrates the use of fibers to reduce treating pressure during a fracturing treatment.
EXAMPLE 44:
Fibers may be used to provide rapid well turnaround, reducing treating costs. Typical wells in the shale formations in Indiana contain several productive zones. Creation of one large fracture to cover all zones in a given well is not a viable solution.
Previous practice had involved fracturing each zone using resin coated proppant. At the end of each treatment, the well is shut in for 12 to 20 hours to allow the resin coated proppant to cure. The well then is allowed to flow for 30 minutes and the next zone then is fractured. In this manner it requires one week on location to fracture four zones in a well.
With the use of fibers at 1.5% by weight of proppant during the last stage of each treatment, the zone fractured may be turned around within ten minutes and then the next zone is fractured. That second zone then is produced for about 30 minutes and then the next (third) zone may be fractured, and so on. In this way, four zones in a single well were fractured in less than 8 hours on location. This results in a sa~ings of 3-4 days of rig time on location that otherwise would be required while waiting for resin coated proppants to cure, followed by subsequent drilling GUt of the cured proppant in the well bore. In most cases, it requires several days on location for a power swivel and bit to drill out cured resin coated proppant. This can reduce costs by several thousand dollars per well. This example illustrates the use of fibers to allow rapid well turnaround, thereby reducing treating costs of multizone wells.

2~ 8~098 EXAMPLE 45:
Creation of fingers or chAnnels in a porous pack may dramatically increase productivity of a well as compared to stAn~Ard fracturing processes. A plexiglass cell was construct2d contA;n;ng a 9~ X 3.875~ X 1.5~
ca~ity. The cell was fitted with a slurry of 501b/1000 gallon guar solution cont~;n;ng 16/20 sand and 1.5%
glass fiber by weight of sand by pumping the slurry through the metal tube through the cell and against the screen on the opposite end. Water then was pumped through the proppant/fiber pack in the same direction to remove residual guar. Air was then pumped through the cell in the same direction to displace most of the water. An aqueous glycerol solution ha~ing a viscosity of 300 cP then was pumped through the screen into the pack and out the open tube. flow rate is was increased up to 50 ml/minute without failure of the pack. This is approximately equivalent to a flow rate of about half a barrel per day of high visco$ity fluid per perforation in a well. As the flow rate is increased, a finger or chAnnel begins to form in the pack. At a rate of 380 ml./minute the ~hAnnel is about 1/2~ in diameter ext~nA;~g the length of the cell. Flow rate can be increased to greater than 1550 ml/min without further 2 1 8~98 changes in the pack. This example illustrates the very high flow rate that can be handled by this channel.
This is one way to dramatically increase the productivity of a well compared to standard fracturing S practices.

EXAMPLE 46:
After a collve~tional fracturing treatment using a 15% resin coated proppant tail-in based upon total volume of proppant pumped, the well is shut in for a sufficient time for the resin coated proppant to cure.
A pad of viscosified fluid is then pumped downhole at less than fracturing rated pressure. The viscosified fluid may be gelled brine or gelled oil. The viscosity of this fluid is at least 50 times greater than that of the next fluid. The next fluid is conventional mud acid cont~i n; ng a mutual solvent such as butyl acetate. This fluid will finger into the previous fluid in the resin coated proppant pack, dissolving the coating and allowing the proppant to be produced back from these fingers once the well is turned around. This reduces well productivity as in the Example immediately preceding this Example.

2~88098 l -EXAMPLE 47:
This example is basically the same as in the Example 46 except that the resin coated proppant tail-in if further stabilized by the addition of 1.5% fibers by weight of resin coated proppant. In this case no shut in time is ne~ and the acid can be pumped ;m~;ately following the viscous fracturing fluid. Or, if desired, the acid treatment may follow the procedure described in Example 46 above. In either case, high productivity 10 ch~nn~l S are created in the pack.

EXANPLE 48:
The use of fibers can allow for optimization of flowback rates to m~X;m;ze polymer removal from the fracture and thereby increase the productivity of a well. In Southern Texas, for example, fractures using resin coated proppant must be flowed back at relatively slow rates, typically less than 250 barrels of water per day. Otherwise, catastrophic failure of the resin coated proppant pack may occur. At this slow rate, only a very limited amount of fracturing fluid and associated polymer residues can be recovered before gas breaks through and begins to be produced from the formation.
Once gas production begins, the water return rate 2 1 ~09~3' decreases and polymer r~m~;nin~ in the fracture can be baked on the proppant surfaces, clogging flow ch~nnels and reducing well productivity. In one well in South Texas, for example, flowback from a resin coated proppant job was monitored. Gas broke through after about 22 hours. At that stage, less than 10% of the fracturing fluid volume had been recovered and less than 10% of the polymer pumped during the job had been returned to the surface. Less than 15% of the total polymer pumped had been returned to the surface after 50 hours of total flowback time.
In contrast, a well was.fractured using fibers to control proppant flowback in this same formation. The water return rate was increased to over 2000 bbl of water per day without failure of the pack. Gas broke through after only 8 hours, but by that time more than 15% of the polymer pumped already had been recovered.
After 50 hours, 25% of the polymer pumped during the fracture treatment had been returned to the surface.
That is nearly twice the clean up efficiency of resin coated proppant fracturing treatments.
In neighboring formations, polymer return rates in excess of fifty percent have been recovered after 50 hours of flowback time.

2 1 88~98 This Example illustrates that use of fibers can allow optimization of the flowback rates to maximize polymer removal from the fracture and thereby increase the productivity of the well.
The invention has been described in the more limited aspects of preferred embodiments hereof, including numerous examples. Other embodiments have been suggested and still others may occur to those skilled in the art upon a re~; ng and underst~n~; ng of the this specification. It is intended that all such embodiments be included within the scope of this invention.

Claims (15)

1. A method of treating an underground formation penetrated by a wellbore using a fluid suspension, comprising the steps of:

(a) providing a fluid suspension, said suspension comprised of a fluid, a particulate material, and a solid material, the solid material being selected from the group of solid materials consisting of metal, polymers, ceramics and glass;

(b) pumping the fluid suspension downhole through a wellbore;

(c) depositing the fluid suspension in the formation;

(d) flowing back fluid from the formation, thereby forming a matrix of solid material and particulate material; and (e) reducing migration of particulate material from the matrix into the wellbore.

2. A method of treating an underground formation penetrated by a wellbore using a fluid suspension, comprising the steps of:

(a) providing a fluid suspension, said suspension comprised of a fluid, a particulate material and shavings of solid polymer material;

(b) pumping the fluid suspension downhole through a wellbore;

(c) depositing the fluid suspension in the formation;

(d) flowing back fluid from the formation, thereby forming a matrix of shavings of solid polymer material and particulate material; and (e) reducing migration of particulate material from the matrix into the wellbore.

3. A method of treating an underground formation penetrated by a wellbore using a fluid suspension, comprising the steps of:

(a) providing a fluid suspension, said suspension comprised of a fluid, a proppant, and solid particles, the solid particles selected from the group of particles consisting of metal, polymers, ceramics, and glass;

(b) pumping the fluid suspension downhole through a wellbore;

(c) depositing the fluid suspension in the formation;

(d) flowing back fluid from the formation, thereby forming a matrix of solid particles and proppant; and (e) reducing migration of proppant from the matrix into the wellbore.

4. A method of treating an underground formation penetrated by a wellbore using a fluid suspension, comprising the steps of:

(a) providing a fluid suspension, said suspension comprised of a fluid, a particulate material, and particles of polymeric material, (b) pumping the fluid suspension downhole through a wellbore;

(c) depositing the fluid suspension in the formation;

(d) flowing back fluid from the formation, thereby forming a matrix of particles of polymeric material and particulate material; and (e) reducing migration of particulate material from the matrix into the wellbore.

5. A method of reducing the production of proppant from a well after fracturing a subterranean formation penetrated by the well, comprising:

(a) pumping a fluid from the surface of the ground through a wellbore and into a subterranean formation, the fluid comprising a viscous liquid, proppant, and shavings or discs of polymer material, (b) forming a matrix within the subterranean formation, the matrix comprising the proppant and polymer material in close association with each other, and (c) reducing production of the proppant from the well.

6, A method of inhibiting flowback of propping agent from a subterranean formation into a wellbore with reduced energy consumption comprising the steps of:

(a) providing a fluid suspension comprising a mixture of a propping agent and fibers;

(b) pumping the fluid suspension including a mixture of the propping agent and fibers through the wellbore using reduced amounts of energy; and (c) depositing the mixture of propping agent and fibers in the subterranean formation.

7. A method of treating an underground formation penetrated by a wellbore using a suspension, comprising the steps of:

(a) providing a suspension, said suspension comprised of a fluid, a particulate material, and solid shavings of material;

(b) pumping the suspension downhole through a wellbore into a formation;

(c) depositing the suspension in the formation;

(d) flowing back fluid from the formation;

(e) forming a porous pack comprised of solid shavings of material and particulate material, further wherein a channel is formed in the porous pack; and (f) wherein the channel is formed by using acid to remove the solid shavings of material from the porous pack.

8. A fluid for treatment of a subterranean formation comprising a viscous liquid consisting of gelled oil, a gelled aqueous fluid, aqueous polymer solutions, aqueous surfactant solutions, viscous emulsions of water and oil and mixtures of any of these fluids with a gas, wherein the fluid has an intimate mixture of a particulate material and a fibrous material suspended therein.

9. The fluid as set forth in claim 8 wherein the particulate material has a size ranging from 10 to 100 U.S. mesh and is selected from a group consisting of sand, resin-coated sand, resin-coated proppant, ceramic beads, synthetic organic beads, glass microspheres and sintered minerals.

10. The fluid as set forth in claim 8 wherein the fibrous material is selected from a group consisting of glass fibers, inorganic fibers, synthetic organic fibers, natural organic fibers, ceramic fibers, carbon fibers and metal filaments; further wherein the fibers and particulate material may be assembled into a matrix, the fibers and particulate material being selectively removable by chemical or physical means to facilitate the formation of channels or voids within the matrix.

11. In a subterranean formation penetrated by a wellbore, a porous pack comprising a particulate material in intimate mixture with a fibrous material;
wherein the particulate material is a fracture proppant selected from a group consisting of sand, resin-coated sand resin-coated proppant, ceramic beads, glass microspheres, synthetic organic beads, resin coated proppant and sintered minerals;
the fibrous material being selected from a group consisting of natural organic fibers, synthetic organic fibers, glass fibers, carbon fibers, ceramic fibers, inorganic fibers, metal fibers and mixtures thereof, wherein the pack is located adjacent the wellbore;
further wherein voids or channels are formed within the porous pack, said voids or channel comprising regions of reduced particulate concentration.

12. A fluid for treatment of a subterranean formation comprising a viscous liquid consisting of gelled oil, a gelled aqueous fluid, aqueous polymer solutions, aqueous surfactant solutions, viscous emulsions of water and oil and mixtures of any of these fluids with a gas, wherein the fluid has an intimate mixture of a particulate material and a fibrous material suspended therein, further wherein the fluid is capable of reducing the frictional force encountered by a fluid suspension in a tubular by pumping the fluid suspension with fibers.

13. A fluid for gravel packing a wellbore within a formation to enhance production, the formation containing hydrocarbons for production from the formation and sand, the fluid comprising a viscous liquid having a mixture of a particulate material and fibrous material suspended therein, the fibrous material being capable of reducing undesirable migration of sand into the wellbore and increasing permeability for production of hydrocarbons from the formation, the fibrous material adapted to prevent the migration of sand into the gravel pack thereby facilitating use of a larger gravel mesh size to increase the permeability of the gravel pack.

14. A fluid suspension adapted for treating an underground formation penetrated by a wellbore comprising (a) viscous fluid, and (b) resin coated sand, (c) wherein the resin coated sand with the viscous fluid forms a matrix within the underground formation, (d) further wherein voids or channels are formed within the matrix by selectively dissolving or removing resin coated sand from the matrix.

15. A fluid for treatment of a subterranean formation comprising a viscous liquid consisting of gelled oil, a gelled aqueous fluid, aqueous polymer solutions, aqueous surfactant solutions, viscous emulsions of water and oil and mixtures of any of these fluids with a gas, wherein the fluid has an intimate mixture of a proppant and fibers suspended therein, further wherein proppant is deposited into the formation with fibers to form a proppant pack, wherein the fluid is capable of reducing the amount of undesirable settling of proppant, the fluid adapted to facilitate lower polymer loadings to transport and place the proppant within the subterranean formation, resulting in a higher permeability proppant pack.