Indian Patents. 199092:A COMPOSITION FOR BREAKING FILTERCAKE DEPOSITE FORMED IN OIL WELLS AND A METHOD OF BREAKING THE SAME

Title of Invention	A COMPOSITION FOR BREAKING FILTERCAKE DEPOSITE FORMED IN OIL WELLS AND A METHOD OF BREAKING THE SAME
Abstract	ABSTRACT IN/PCT/2001/00911/CHE "A composition for breaking filtercake deposit formed in oil wells and a method of breaking the same" This invention relates to a composition for breaking filtercake deposit formed in oil wells comprising a viscoelastic surfactant and an enzyme. The present invention also relates to a method of breaking the same"

Full Text	Technical Field of the Invention The Invention relates to novel fluids and techniques to optimize/enhance the production of hydrocarbon from subterranean formations, in particular, fluids and techniques are disclosed and claimed which remove wellbore and near-wellbore formation damage in the form of coating formed from drilling and production-related operations; the techniques can be applied either by themselves or in conjunction with other completion operations, such as gravel packing. Background of the Invention The present Invention relates to novel fluids and techniques to /optimize/enhance the production of hydrocarbons from subterranean formations. To recover hydrocarbons (e.g., oil, natural gas) it is of course necessary to drill a hole in the subsurface to contact the hydrocarbon-bearing formation. This way, hydrocarbons can flow from the formation, into the wellbore and to the surface. Recovery of hydrocarbons from a subterranean formation is known as "production." One key parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore. Sometimes, the formation rock has a naturally low permeability, other times, the permeability is reduced during, for instance, drilling the well. When a well is drilled, a fluid is circulated into the hole to contact the region of the drill bit, for a number of reasons— including, f to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling. Drilling fluid is expensive particularly in light of the enormous quantities that must be used during drilling. Additionally, drilling fluid can be lost by leaking off into the formation. To prevent this, the drilling fluid is often intentionally modified so that a small amount leaks off and forms a coating on the wellbore, or a "filtercake." Yet once drilling is complete, and production is desired, then this coating or filtercake must be removed. The present fluids and techniques are directed to removing this filtercake or other such damage in the wellbore and near-wellbore region, that results either intentionally (in the case of drilling fluid) or unintentionally (in the case of scale deposits from produced water or dewatered fluids from workover/stimulation operations performed on the well). Conventional treatments for removing filtercake include: aqueous solution with an oxidizer (such as persulfate), hydrochloric acid solution, organic (acetic, formic) acid, combination of acid and oxidizer, and aqueous solutions containing enzymes. For instance, the use of enzymes to remove filtercake is disclosed in U.S. Pat. No. 4,169,818, Mixture of Hydroxypropylcellulose and Poly(Maleic Anhydride/Alkyl Vinyl Ether) as a Hydrocolloid Gelling Agent (1979) (col. 1, In. 42); U.S. Pat. No. 3,515,667, Drilling Fluid Additive (1970); U.S. Pat. No. 3,509,950, Well Drilling Mud and Screen Compsition of Use Thereof U.S. Pat. No. 2,259,419, Well Drilling (1941). Chelating agents (e.g., EDTA) are also used to promote the dissolution of calcium carbonate. See, C.N. Fredd and H.S. Fogler, Chelating Agents as Effective Matrix Stimulation Fluids for Carbonate Formations, SPE 372212 (1997); C.N. Fredd and H.S. Fogler, Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing, SPE 31074 (1996), both articles are hereby incorporated by reference in their entirety. According to conventional teaching, the oxidizer and enzyme attack the polymer fraction of the filtercake; the acids mainly attack the carbonate fraction (and other minerals). Generally speaking, oxidizers and enzymes are ineffective in degrading the carbonate fraction; likewise, acids have very little effect on polymer. In addition, nimierous problems plague conventional techniques of filtercake removal. Perhaps the most troublesome is the issue of "placement." For instance, one common component in filtercake is calcium carbonate. The substance of choice to remove calcium carbonate is hydrochloric acid . Hydrochloric acid reacts very quickly with calcium carbonate. What happens then, is that the filtercake begins to dissolve, therefore dramatically increasing the permeability of the wellbore face, so that the wellbore region is no longer "sealed off from the formation. Once this happens, the entire clean-up fluid may then leak off into the formation through this zone of increased permeability ("thief zones," or discrete zones within the interval of very high permeability where more filtercake dissolution has occurred than at other places along the interval). A second problem with removal of filtercake is that it is comprised of several substances, and which are, as mentioned earlier, not generally removable with a single substance. Calcium carbonate and organic polymers (e.g., starch and other polysaccharide) are two primary constituents of conventional drilling fluids that form a filtercake on the wellbore. Treating these successively—i.e., with two different fluids, one after the other—is problematic since, it requires at least two separate treatments. Combining two different breakers (one for the polymer fraction, one for calcite) is problematic since each has a distinct activity profile (or optimal window of activity, based on temperature, pH, etc.) and the activity profiles of two different breakers may not coincide. This is particularly likely if one of the breakers is an enzyme, which are notoriously temperature and pH sensitive. Moreover, if the calcium carbonate is removed first— as it often is— then, once the hydrochloric acid contacts the filtercake, regions of higher permeability are created in the wellbore (where the filtercake has dissolved). Hence, fluid will leak-off into the formation during subsequent phases of the filter-cake removal treatment. Hence, the ideal fluid must be easy to "spot" or place in wellbore over the entire length of the desired zone, contiguous with the producing zone (e.g., a two thousand foot horizontal zone)—before any filtercake dissolution occurs. If the fluid begins to dissolve the filtercake too quickly, then the fluid will be lost through the thief zones and the entire fluid treatment will be destroyed. In other words, a hypothetical ideal fluid would be completely unreactive for a period of time to enable it to be spotted along the entire length of the producing interval, then, once in place, react sufficiently slowly and uniformly, so that no thief zones are. Again, if thief zones form, then the entire mass of fluid can leak off through that zone. Hence, reasonably uniform/controlled dissolution is necessary to ensure that the fluid remains in contact with the filtercake along the entire interval until near-complete dissolution of the filtercake has occured along the entire interval. Moreover, removing filtercake is an expensive and time-consuming procedure. Therefore, it is desirable to do this at the same time that another treatment is being performed, if possible. For instance, if a material must be delivered to one portion of the formation into the wellbore (e.g., in conjunction with a remedial treatment), then the fluid used to carry that material can be an acid solution which will also dissolve portions of the filtercake. Again, if the carrier fluid leaks off into the formation through a thief zone, then the remedial operation is completely destroyed. One common treatment performed on wells, particularly wells in the Gulf Coast region of the United States, is known as a "gravel pack." Gravel pack operations are performed to prevent the production of sand along with hydrocarbon, which often occurs in formations of weakly consolidated sands. To prevent sand production, a filter (or screen) can be placed around the portion of the wellbore in which production occurs. A more long-term solution for sand control is achieved if the region between the screen and the formation is filled with gravel, which is properly sized to prevent the sand from moving through the gravel and into the wellbore—to function as a filter—so that when the sand tries to move through the gravel, it is filtered and held by the gravel or screen, but hydrocarbon continues to flow unhindered (by either the gravel or screen) into the wellbore. Again, it would be highly advantageous if the fluid used to deliver the gravel could also be used to dissolve the filtercake, which would iminate the need for a separate treatment just to dissolve the filtercake. his would result in substantial cost savings—both because a separate eatment is costly, and because it take additional time to perform such a eatment. Thus, what is desired is a fluid that can be used as a carrier fluid hough it need not be used for that purpose) and that can also degrade the Itercake. An ideal carrier fluid is inert— i.e., it should not degrade the ltercake instantaneously (otherwise the fluid can be lost into the prmation)—but an ideal filtercake dissolution fluid must dissolve the ake, eventually. Therefore, an ideal fluid must somehow combine these two contradictory attributes. Indeed, the need for filtercake clean-up is particularly acute in gravel ack completions— i.e., wells in which the movement of sand along with the hydrocarbon is prevented by a gravel pack/screen combination— lecause, the entrapment of the filter-cake between the formation and creens or gravel can result in substantial reduction in production. The beed for a reliable filtercake clean-up treatment with a good diversion mechanism (to ensure proper placement) is also particularly acute in horizontal, or highly deviated wells. In these cases, the producing interval nay be several thousand feet, compared with a vertical well, which may lave a producing zone of about 30 feet. Because the difficulty of placing a nass of fluid to achieve near-uniform dissolution over 1000 feet interval is ar greater than for a 30 feet interval—placement takes longer, and the potential for the creation of thief zones is far greater. Therefore, an urgent need exists in the drilling and completions sector for a reliable fluid for degrading filtercake— quickly, efficiently, and completely, and which can be used as a carrier fluid in conjunction with other completion/workover/stimulation operations. This is the primary objective of the present invention. Summary of the Invention The present invention relates to fluids intend to break filtercake (whether produced from drilling, production, completion, workover, or stimulation activity, either produced intentionally or unintentionally. In particularly preferred embodiments, the fluids and techniques are directed to degrading (or "breaking") filtercake formed from starch/carbonate-containing drilling fluid such as the STARDRILLTM (a drill-in fluid manufactured and sold by Schlumberger). In other particularly preferred embodiments, the fluids of the present Invention are operable in conjunction with a gravel pack operation, and in particular, though not exclusively, to break filtercake, in conjunction with a gravel pack operation. Therefore, one object of the present Invention is to provide novel completion fluids to break filtercake, either alone or in conjunction with other workover/completion/stimulation treatments, but in particular, gravel pack operations. Preferred embodiments relate to fluids to break filtercake having substantial calcite and starch content. Particularly preferred embodiments related to treatment fluids having two essential components; a chelating agent and an enzyme for example a-amylase or P-amylase. These components were selected based on their ability to dissolve different components of the filtercake, and based on their ability to dissolve these components at particular rates relative to one another. Other particularly preferred — embodiments are fluids having these two components in a VES (viscoelastic surfactant) system. VES systems have niunerous advantages-discussed at length in U.S. Patents incorporated by reference below-including that they are readily gelled, they can be disposed of more easily than guar and modified guar systems, they are more readily removed from subsurface formations. In addition, and of particular importance of the present Invention, VES systems create very low friction pressures compared with conventional carrier fluids, and therefore they are particularly preferred, for instance, in gravel pack operations of the present Invention. The fluids of the present Invention can be successfully spotted or placed over, for instance, a 2000 ft. horizontal producing zone—without substantial leakoff. Particularly preferred embodiments to achieve this incorporate Mobil's AUPAC" (licensed exclusively to Schlmnberger). This way, the gravel pack operation, for instance, can take place without fluid loss. At the same time, the fluid of the present Invention acts slowly upon the filtercake, to slowly but steadily dissolve it, but not before the particular workover operation has been completed. Moreover, the break time (or time to substantial dissolution of the filtercake) of the fluids of the present Invention are optimized so that the overall or blended dissolution rate is very slow at low temperatures but much higher at high temperatures. The primary advantage of this unique temperature-dependence is that fluid can be introduced into the entire zone of interest before filtercake dissolution occurs, then as the fluid temperature rises due to contact with the wellbore, only then does dissolution occur. The fluids and techniques of the present Invention are quite general and are operable in a variety of settings. These include, but are not limited to, screen-only completions and gravel pack completions; open hole and cased hole; vertical and highly deviated wells; single-application soak or circulating fluid in which the treatment fluid (of the present Invention) also serves as a carrier fluid for, e.g., a gravel pack operation; In. conjunction with a gelling agent or viscoelastic surfactant (e.g., ClearFRAC'") or alone, and with a variety of clean-up tools. In summary, since the problem of placement and uniform dissolution are present in virtually every instance, the fluids and techniques of the present Invention are readily applicable to any scenario in which it is desirable to remove filtercake from the wellbore or near-wellbore region in the formation, regardless of whether the filtercake was produced during drilling or during other post-drilling operations (e.g., fluid-loss control pill, gravel pack operation, fracturing, matrix acidizing, and so forth). Finally, the fluids of the present Invention are a viable, cost-effective replacement for HCl-based fluids, conventional fluids of choice to remove filtercake. Perhaps the major problem with HCl systems (aside from their ineffectiveness in removing the carbonate fraction of filtercake) is corrosion—corrosion of the above-ground storage tanks, pumps, down-hole tubulars used to place the fluid, and wellbore casings. Moreover, a cost-effective solution to corrosion is not readily available, as evidenced by the fact that corrosion inhibitors is a significant portion of the total expense of a filtercake remove (or matrix-acidizing) treatment. With many of the fluids of the present invention (those that do not contain acid) the problem of corrosion is drastically minimized. Additionally, personnel safety and environmental concerns are significantly reduced with the fluids of the present invention. Accordingly, the present invention provides a composition for breaking filtercake deposit formed in oil wells comprising a viscoelastic surfactant and an enzyme. Accordingly, the present invention also provides a method of breaking filter cake deposit formed in oil wells for subsequent removal operations comprising, introducing and circulating through a well bore the composition such as herein described. With reference to the accompanying drawings, in which Figure 1 shows change in viscosity of various VES solutions at 100 sec' ifter 101 minutes at 180° F, upon addition of K2-EDTA, a-amylase, mmionium persulfate— either separately or in combination. These data show for instance, that the viscosity of VES is not significantly affected by the addition of 0.5% a-amylase, nor is it affected by the addition of 0.5% a-amylase and 28% K2-EDTA. Figure 2 shows the effect of various combinations of a-amylase and K2-EDTA on VES (5% by volume) rheology: 3% NH4CI and 28% K2-EDTA (diamonds) ; 4% KCl (open boxes); 4% KCl in 28% K2-EDTA (triangles); 3% NH4CI and 0.5% a-amylase and 28% K2-EDTA (diagonal crosses with vertical lines); 3% HN4CI in tap water (diagonal crosses); 3% NH4CI and 0.5% a-amylase (open circles); 4% KCl and 0.5% a-amylase in tap water (venical Hnes); 4% KCl and 0.5% a-amylase in 28% K2-EDTA (light open boxes). These data show, for instance that the addition of a-amylase in a VES solution does not significantly affect VES-solution viscosity at 100 sec', yet if a-amylase is added to a VES solution to which 28% K2-EDTA and KCl are also added, then viscosity is significantly reduced—though not if NH4CI is used instead of KCl. Figure 3 shows the effect of VES (5%) on the cake-breaking activity of both enzyme and conventional oxidizer breakers. The white bars represent (from left to right): (1) no VES, 0.5% a-amylase, 4% KCl; (2) no VES, 1% ammonium persulfate, 4% KCl. The black bars represent: (1) no VES, 0.5% a-amylase, 4% KCl, (2) VES, 4% KCl; (3) VES 1% ammonium persulfate; (4) VES, 1% ammonium persulfate, 0.1% triethanolamine, 4% KCl. The gray bars represent: (1) VES, 0.5% a-amylase, 28% K2-EDTA, 4% KCl; (2) VES, 28% K2-EDTA, 4% KCl; (3) VES, 1% ammonium persulfate, 28% K2-EDTA, 4% KCl; (4) VES, 5% (low temperature-optimized) ammonium persulfate, 28% K2-EDTA, 4%; (5) VES, 5% encapsulated ammonium persulfate, 28% K2-EDTA, 4% KCl. All assays were conducted at 150° F. These data show that VES impairs but does not entirely destroy cake-breaking activity. Figure 4 shows the effect of VES (5%) on two breaker types (a-amylase and ammonium persulfate), (1) 1% ammonimn persulfate, no VES (thin gray line); 1% ammoniimi persulfate, VES (think black line); (2) 0.5% a-amylase, no VES (thick gray Hne), 0.5% a-amylase, VES (thick black line). These data show that VES is compatible with these two breaker systems. Figure 5 shows the effect of VES on K2-EDTA cake-breaking activity, 5% VES, 28% K2-EDTA (light gray line), 5% VES, no K2-EDTA (dark gray line), no VES, 28% K2-EDTA (black line). These data show that the presence of VES substantially affects K2-EDTA activity. Figure 6 shows the rheology (shear rate versus viscosity) of two different types of VES systems (VES and VESJ, a 28% K2-EDTA/0.5% a-amylase system in 5% VES at 125 °F (light triangles) compared with similar systems, no a-amylase (crosses), 1.5% VES at 75 °F (plus K2-EDTA/a-amylase) (dark triangles), 5% VESi at 140 °F (diamonds). These data show that the rheology of a different VES system is not significantly affected by the addition of K2-EDTA/a-amylase. Figure 7 is identical to Figure 6 expect that the system was tested at 200° F instead of 125 °F. These data show no significant difference in activity of the systems under study at 125 versus 200° F. Figure 8 shows the viscosity (at 170 s") of a 3% VES solution at 80° F as a function of HCl concentration. These data show that, above 157o HCl (between 15 and 25%) solution viscosity decreases, but below that, the VES-stability is not affected by the acid. Figure 9 compares the effect of a-amylase and ammonium persulfate in 5% VES/28% K2-EDTA solutions, 0.5% a-amylase (black line with crosses), no polymer break (gray line), 1% ammonium persulfate (black line). These data show the superior activity of a-amylase over ammonium persulfate in a VES/K2-EDTA system. Figure 10 compares the effect of different salts on the rheology of a 5% VES + 27.3% K2-EDTA system: 4% potassium chloride (no K2-EDTA) (crosses); 3% ammonium chloride (circles) (no K2-EDTA); 4% potassium chloride (vertical lines); 3% ammonium chloride (flat boxes). These data show that K2-EDTA does not substantially affect the viscosity of the 5% VES system. Figure 11 shows a comparison of break times (filtercake degradation) for three different systems: 15% HCl (diamonds), 9% formic acid (squares), and 28 % K2-EDTA. These data show that the HCl system breaks the filtercake more rapidly that the other two systems. Figure 12 shows the effect of a-amylase on a K2-EDTA/VES system on the system's cake-breaking activity. The systems shown are control/blank (diamonds), K2-EDTA/VES only (squares), and K2-EDTA/VES with a-amylase. These data show that the addition of the enzyme substantially enhances leak-off (a proxy for filtercake degradation), and that this effect occurs very quickly ( Figure 13 shows a comparison of two systems with respect to their capacity to break filtercake. The two systems are K2-EDTA only (diamonds) and K2-EDTA, and a-amylase (squares). These data show that more complete break occurs with the K2-EDTA/a-amylase system (after approximately 500 minutes). figure 14 compares retained permeability for a 5% VES system in 3% TH4CI (2 brs., 300 psi, 150 °F) upon addition of various breakers, from :ft to right: nothing, VES only, 28% K2-EDTA only; 14% K2-EDTA; 28% K2-EDTA at pH 5.5; 28% K2-EDTA + 0.5 a-amylase; and 0.5% -amylase. These data show that the K2-EDTA + a-amylase system gives operior retained permeability. Detailed Description of the Preferred Embodiments Again, the center of gravity, though not the exclusive scope, of the resent Invention, is a set of fluid compositions and techniques for emoving de-watered drilling fluid (i.e., "filtercake"). In general, fluids hich perform this function are referred to as "completion fluids." The common denominator of preferred embodiments (completion fluids) of be present Invention is they are specifically, though not exclusively, ptimized to degrade/remove drilling filtercake produced from a certain ind of drilling fluid—a drill-in fluid system, known by the trademark, FARDRILL™. Primary components of STARDRILL are calcite, starch, and lesser concentrations of either xanthan or scleroglucan. The fluids of the present Invention were designed based on mierous criteria, two primary criteria are: (1) rheology, i.e., ensuring lat the fluid rheology at bottom hole circulating temperature fell with ceptable limits (e.g., sufficient viscosity to deliver gravel) over a wide ear rate range; and (2) clean-up, i.e., ensuring that the formulations were fective at removing filtercake while minimizing damage to the formation and not unduly interfering with a contemporaneous completion (e.g., gravel pack). In addition, any system design that combines an enzyme and other breakers must account for the variable activity windows of the different breakers, particularly since some enzymes are highly pH and temperature sensitive. Example 1 Stability of VES Systems in the Presence of Breakers Again, one object of the present Inveniton is to provide novel fluids that will degrade filtercake and which can also serve as carrier fluids in conjunction with other well treatments, particularly, gravel pack operations. In the case of gravel pack operations, the carrier fluid must be viscous in order to transport the gravel. Thus, VES systems are preferred. Again, VES stands for "viscoelastic surfactant." The use of VES for well treatment fluids has validated in numerous actual well treatments. Well treatment fluids based on VES are the subject of numerous patents and patent applications, each assigned to Schlumberger, and incorporated by reference in its entirety. U.S. Pat. No. 5,258,137, Viscoelastic Surfactant Based Foam Fluids, assigned to Schlumberger Technology Corporation, 1993; U.S. Pat. No. 5,551,516, Hydraulic Fracturing Process and Compositions, Schlumberger Technology Corporation, 1996 ; U.S. Pat. Appl. Ser. No. OS/727,877, Methods of Fracturing Subterranean Formations, assigned to Schlumberger Technology Corporation, filed 9 October 1996; U.S. Pat. Appl. Ser. No. 08/865,137, Methods for Limiting the Inflow of Formation Water and for Stimulating Subterranean formations, assigned to Schlumberger Technology Corporation, filed 29 May 1997; U.S. Pat. Appl. Ser. No. 09/166,658, Methods of Fracturing tubterranean Formations, assigned to Schlumberger Technology Corporation, filed 5 October 1998. In the Examples that follow the VES system most often used is N- is-13-docosenoic-N,N-bis(2-hydroxymethyl)-N-methyl ammonium hloride (a.k.a. iV-erucyl-Ar,iV-is(2-hydroxyethyl)-7-methyl ammoniimi hloride). In addition, the actual VES system used in the Examples ontains 25% tso-propanol to enhance VES stability at low temperatures, n some instances, a second VES system is used, referred to as VES, and which consists of glyceryl esters of three different fatty acids, 23.5% erucyl C22 with one double bond), 32% oleic (C with one double bond) and W.5% linoleic (Cg with three double bonds separated by methylene groups) acids. In addition, the VES systems referenced above are fully compatible with seawater in addition to ordinary tap water. Thus, the term "VES" ;ubsumes VES systems prepared from seawater in addition to freshwater. VES systems prepared from seawater are disclosed and claimed in U.S. Pat. A.ppl. Ser. No. 09/166,658, Methods of Fracturing Subterranean Formations, filed 10 October 1998, and assigned to Schlumberger. This appUcation is tiereby incorporated by reference in its entirety, and particularly with respect to that portion disclosing the operabiUty of VES systems prepared from seawater. The experimental results that follow illustrate that VES systems retain their stability (viscosity) upon addition of the breakers (either alone or in combination) of the present Invention. The following experimental protocol was observed for the data collected and presented in the Examples that follow. First a dry sandstone core was weighed, then saturated with brine (to water wet the core) and then weighed again. Based on comparison of these two measurements, a pore volune was determined. Next, the core was heated to test temperature (150 °F). Then, 100 pore volumes of kerosene was flowed through the filtercake core, at about 10 psi. The purpose of this step is to fill the pores with hydrocarbon. The sandstone core's permeability to kerosene was then observed. Next, the kerosene is poured off, then 125 ml of STARDRILL drilling fluid was applied to the core under a pressure of 300 psi for about one hour. The goal is simulate overbalanced conditions within a typical wellbore; hence, the STARDRILL fluid was "forced" into the core to mimic leakoff. After one hour, the excess STARDRILL was poured off, and the core was rinsed with brine. Next, the STARDRILL filtercake-coated core was contacted with a series of "clean-up" solutions— 100 ml, at 300 psi for 2 hours (to simulate, e.g., a typical gravel pack operation). In the case of the data presented in Figure 14, for instance, each clean-up solution consisted of a matrix of 5% VES in 3% NH4CI. These solutions are (from left to right in Figure 14): "backflow" (to simulate allowing the well to produce without any clean¬up) "blank" (VES only), 28% K2-EDTA; 14% K2-EDTA; 28% K2-EDTA at pH5.5; 28% K2-EDTA + 0.5% a-amylase; and 0.5% a-amylase. In each instance, the amount of clean-up solution contacted with the sandstone core was 100 ml. After two hours, the leak-off volumes were observed; the retained permeability to kerosene was measured at the test temperature. Upon preparing the breaker systems in the VES matrix, none of the fluids showed sedimentation or phase separation; however, when the pH of the VES in 28% K2-EDTA) was increased to values higher than 11, a white waxy substance was observed. Apparently at this high pH, the EDTA-complex interferes with the surfactants and worm-like micellar structure in the VES system. The viscosity of the systems under study was measured using API Standard ramps at 180F (lOOsec* viscosity). The source of the viscoelastic behavior and the high low-shear viscosity of VES-based solutions is the wormlike micellar structure formed by the surfactants (either 4% KCl or 3% NH4CI). Addition of filtercake-breakers may affect this micellar structure, and hence also the the rheological behavior of the VES solutions. This can occur either through reaction of the additive with the VES-surf actant molecule or by interaction of the additive VES with the ClearFrac™ micellar structure. The results shall now be discussed. Figure 1 is an overview of the viscosities measured for 5% VES-solutions with various additives. The values correspond to 100 s' after shearing the sample at 100 s" for 101 minutes. This viscosity is calculated from the API-ramps that were taken at that point. These data show for instance that VES viscosity (and probably the microscopic micellar structure) are not significantly affected by the addition of either EDTA or a-amylase, or by the addition of the two breakers together. Figure 2 reports related data. There, the effect of the addition of starch-breaking enzyme a-amylase on VES rheology is shown. According to Figure 2, addition of a-amylase to a VES-in-brine solution does not significantly affect the viscosity of VES at 100 sec" Yet, when a-amylase is added to VES in EDTA/KCl brine, the viscosity is reduced considerably. It is striking that this effect does not occur if EDTA/NH4CI brine is used. Repetition of both tests gave similar results. Figure 6 shows the effect on the rheology of VES systems to which 28% K2-EDTA and 4% KCl are added (at 125° F if not specified). These data show that the rheology of VES is not significantly affected by the addition of either K2-EDTA or a-amylase, or both. Figure 7 presents similar data though at higher temperature. In addition what these two Figures also show is that both 5% VES (short-chain) VES at 140° F and 1.5% (long-chain) VES at 75 ° F are competent gravel pack carrier fluids. Hence, in accordance with the present Invention, it is now possible to formulate gravel pack carrier fluids containing filter cake breakers for 125 and 150° F, that have similar rheology. Figure 8 shows the effect of varying HCl concentration on the viscosity of a 3% VES system at 80° F. As evidenced by these data, viscosity is barely affected from about 5% HCl to about 15% HCl, after which viscosity falls off significantly. Finally, Figure 10 compares the effect of different salts (sodium salicylate, KCl, and NH4CI) on the rheology of a 5% VES system. These data convincingly demonstrate that K2-EDTA (at up to 28%, which is roughly the solubility Hmit of EDTA in water) does not substantially affect the viscosity of a 5% VES system. Additionally, these data show that neither KCl nor NH4CI affects the rheology of the 5% VES system; however, soditun saUcylate, even at very low concentrations (0.5%) has a dramatic effect on VES viscosity when EDTA is present (an approximately 40% decrease in viscosity). From these data, two sets of particularly preferred embodiments emerge. These are completion fluids having both a-amylase and EDTA with or without VES. Yet if VES is used as the matrix, then the preferred salt is NH4CI at about 3%. Thus, one particular preferred completion fluid of the present Invention contains: 5% VES, 0.5% a-amylase, and 28%' K2-EDTA, in a 4% NH4CI solution. Another particular preferred fluid is: , 0.5% a-amylase, and 28% K2-EDTA, in a 4% salt solution (the salt type is less critical if VES is not used). Without intending to be bound by this suggested mechanism, we posit that the combination of chelating agent and enzyme (e.g., K2-EDTA and a-amylase) operate in synergy to break filer cake comprised of starch and calcite. More particularly, the starch polymer and the calcite are arranged in a complex configuration, e.g., the polymer coating the calcite particles. Thus, a breaker that acts primarily upon the polymer (e.g., an enzyme) will simply degrade the particle coating, but leave the particles untouched. Similarly, a breaker that acts primarily upon the calcite particles will have difficulty reaching them due to the polymer coating— hence the observed synergistic activity of the enzyme + chelating agent combination fluid. The goal of an ideal completion fluid is that it degrade the filtercake to the greatest extent possible while at the same time ensuring a high retained permeabiHty. Thus, a completion fluid that resulted in maximum filtercake degradation but that left filtercake particles embedded in the wellbore, is ineffective, since retained permeabiHty will be low. Therefore, the degradation must be even and complete— i.e., result in small particles that cannot plug the wellbore, but that can be removed in a circidating wash or can be produced with the hydrocarbon. Example 2 Breaker Activity in VES systems The previous Example adequately demonstrated that VES systems are stable—i.e., their viscosity is not substantially affected in the presence of the breakers of the present Invention (e.g., HCl, formic and acetic acid, enzymes, and chelating agents). This Example demonstrates that the VES matrix does not substantially affect the activity of the breakers— i.e., with respect to breaking filtercake. Figure 3 shows the effect of VES (5%) on the activity of both enzyme (a-amylase) and conventional oxidizer breakers (ammonium persulfate, dissolved and encapsulated). These data show that VES inhibits the activity of breakers of proven efficacy. As evidenced by Figure 4, the data presented in Figiire 3 must be qualified by an evaluation of the time-dependence of these systems. Figure 4 shows that VES actually increases the activity of a-amylase over approximately the first 65 minutes of the test. Figure 5 shows the results of an K2-EDTA system (in the presence if 5% VES and without). These results show that VES does have a ubstantial effect on EDTA activity. Example 3 Performance of the Completion Fluids of the Present Invention Having shown that the various breaking agents (e.g., acid, enzymes, nd chelating agents) separately or in combination, are effective in VES Dlutions (as well in non-VES solutions) and having shown to what extent iese agents are affected by the VES, we shall now demonstrate in more etail the superior performance of the completion fluids of the present ivention. The purpose of this Example is to demonstrate that certain Drmulations of the present Invention exhibit superior filtercake 2moval—compared with conventional systems. The experimental rotocol in this Example was carefully designed to simulate, as closely as ossible, actual conditions in an exemplary water-wet, oil-saturated, mdstone reservoir. The data presented in Figure 9 compares the effect of a-amylase ersus an oxidizer breaker (ammonium persulfate) in a VES/K2-EDTA astern (5% VES, 28 % K2-EDTA, 4% KCl). These data show that an izyme + EDTA system is unquestionably superior to an oxidizer + DTA system. These data are surprising since, while the EDTA is irected to the calcite fraction of the filtercake, the oxidizer and a-amylase •e directed to the polymer fraction. Therefore, both binary systems are ;omplete" in that they contain a breaker for each of the two fractions comprising the filtercake, hence one might expect comparable filtercake removal rates (or extent). Figure 11 presents data that compares the activity (break times) of 15% HCl, formic acid, and 28% K2-EDTA in 5% VES, as a function of temperature. As evidenced by Figure 11, the EDTA system outperforms the acid systems by a substantial margin, particularly at lower temperatures. Figures 12 and 13 compare the activity of an EDTA system versus an EDTA/a-amylase system, in VES (Figure 12) and without VES (Figure 13). A comparison of the two Figures shows that the EDTA-only system is actually enhanced in the presence of VES, though this effect is imobservable prior to about 90 minutes. Figure 12 corroborates earUer data showing the superior performance of the chelating agent/enzyme system compared with chelating agent by itself. Figure 12 also shows that this effect is very rapid— less than one minute). The leak-off data of Figure 14 is consonant with that presented in Figure 12. Most significantly though. Figure 14 shows that the EDTA/a-amylase system gives the highest retained permeabiUty—over 90%, compared with the EDTA-only system which resulted in a retained permeabiHty of just over 80%. Therefore, the VES/EDTA/a-amylase system of the present Invention is demonstrably superior to conventional clean-up formulations on both relevant axes of comparison: leak-off and retained permeabiUty. Moreover, results presented earUer (e.g.. Figure 4 for a-amylase; Figure 5 for EDTA) show that VES is a viable carrier fluid for the EDTA/a-amylase system. Similarly, as evidenced by the results resented in Figures 1 and 2, the EDTA/a-amylase system activity does lot significantly affect the characteristics of the VES matrix (e.g., ascosity). Finally, the skilled treatment designer will recognize that chelating igents other than EDTA are operable in fluid compositions of the present iivention. The relevant parameters for selection of the fluid are the :alcite (or other mineral) dissolution constant (a thermodynamic )arameter), the proton dissociation constants (also thermodynamic jarameters), and kinetic parameters. The skilled treatment designer can nfer the behavior of other chelating agents by comparing those parameters for EDTA with those for the chelating agent under :onsideration. A systematic study of the kinetics of calcite dissolution by various chelating agents (including EDTA, DTP A, and CDTA) is )resented in C.N. Fredd and H.S. Fogler, The Influence of Chelating Agents m the Kinetics of Calcite Dissolution 204 J. ColHod Interface Sci. 187 (1998). This article is incorporated by reference in its entirety. Example 4 Specialized Applications The fluids and techniques of the present Invention are quite general md are operable in a variety of settings. Since the problem of placement md imiform dissolution are present in virtually every instance, the flxiids md techniques of the present Invention are readily appHcable to any cenario in which it is desirable to remove filtercake from the wellbore or lear-wellbore region in the formation, regardless of whether the filtercake vas produced during driUing or during other post-drilling operations (e.g.. luid-loss control pill, gravel pack operation, fracturing, matrix acidizing, ind so forth). The fluids and techniques of the present Invention are ippHcable in numerous different environments, including: • screen-only completions and gravel pack completions; • open hole and case hole; • vertical and highly deviated wells; • single-stage soak fluid or circulating fluid in which the treatment fluid (of the present Invention) also serves as a carrier fluid for, e.g., a gravel pack operation; • in conjunction with a geUing agent such as a viscoelastic surfactant (e.g., ClearFRAC™) or alone; • with a variety of clean-up tools and unconventional technologies (e.g., Mobil's Alternate Path Technology, see, e.g., L.G. Jones, et al.y Gravel Packing Horizontal Wellhores With Leak-Ojf Using Shunts, SPE 38640, hereby incorporated by reference in its entirety); or • in conjimction with other fluid additives (e.g., anti-corrosive agents) or dissolution components (e.g., an oxidizer). One such specialized setting in which the fluids of the present Invention can be appUed is a particular type of gravel pack operation known as "AllPAC or Alternate Path technology. (As used herein, the term "gravel pack" includes treatments incorporating the AllPAC technology. This technology is described in a number of patents, each is assigned to Mobile, and licensed exclusively to Schlumberger: U.S. Pat. No. 5,560,427, Fracturing and Propping a Formation Using a Downhole Slurry Splitter (1996); U.S. Pat. No. 5,515,915, Well Screen Having Internal Shunt Tubes (1996); U.S. Pat. No. 5,419,394, Tools for Delivering Fluid to Spaced Levels in a Wellbore (1995); U.S. Pat. No. 5,417,284, Method for Fracturing and Propping a Formation (1995); U.S. Pat. No. 5,390,966, Single Connector for Shunt Conduits on Well Tool (1995); U.S. Pat. No. 5,333,688, Method and Apparatus for Gravel Packing of Wells (1994); U.S. Pat. No. 5,161,613, Apparatus for Treating Formations Using Alternate Flopaths (1992); U.S. Pat. No. 5,113,935, Gravel Packing of Wells (1992); U.S. Pat. No. 5,082,052, Apparatus for Gravel Packing Wells (1992); U.S. Pat. No. 4,945,991, Method for Gravel Packing Wells (1990). Each of these patents is incorporated by reference in its entirety. The significance of the AllPAC technology to the fluids and techniques of the present Invention cannot be over-emphasized. Without AllPAC, gravel packing with a viscous carrier fluid is very difficult, in some instances, virtually impossible. AllPAC screen is comprised of shimt tubes which permit the easy flow of viscous fluid through the screen annulus to its intended situs. In addition, a thorough discussion of filtercake removal in conjunction with sand control operations, in open-hole horizontal wells is provided in C. Price-Smith, et. al. Open Hole Horizontal Well Cleanup in Sand Control Completions: State of the Art in Field Practice and Laboratory Development, SPE 50673 (1998). This article is incorporated by reference in its entirety. The ALLPAC technology incorporates a novel gravel pack screen device which contains "shunt-tubes" or alternate flow paths, attached to the sides of the screen. These shunt tubes permit effective gravel packing by eliminating bridging (or more precisely, by letting the fluid flow around a bridged zone), thus even long horizontal sections can be gravel packed even with high fluid loss. Therefore, when the fluids of the present Invention are used in conjunction with the ALLPAC technology, a novel method is enabled. In this method, the filtercake is readily cleaned up during the gravel pack operation since fluid loss (leak-off) will not substantially interfere with the quahty of the gravel pack. Thus rig time is substantially reduced by combining filtercake removal with gravel pack treatment. Indeed, combined gravel pack/filtercake removal treatments the fluids of the present Invention incorporating the AllPAC technology provide a cost-effective means to complete a well. A yard test with a single shunt tube placed in side a slotted liner packed an entire length of 2,000 ft using the VES. During this test, it was foimd that 40/60 gravel (approx. 50 darcies) was sufficient to divert flow down the shunt tube. Again, leak off is not a concern, which is another substantial advantage of the AllPAC technology as it is exploited using the fluids and methods of the present Invention. Preferably, this composition is allowed to remain in the wellbore for 24 to 128 hours. WE CLAIM: 1. A composition for breaking filtercake deposit formed in oil wells comprising a viscoelastic surfactant and an enzyme. 2. The composition as claimed in claim 1, wherein said viscoelastic surfactant is N-cis-13-docosenoic-N,N-bis(2-hydroxymethyl)-N-methyl-ammonium-chloride. 3. The composition as claimed in any of the preceding claims wherein said viscoelastic surfactant is present in said composition at a concentration between 0.5% and 7%. 4. The composition as claimed in any of the preceding claims wherein iso-propanol is added and said iso-propanol and said viscoelastic surfactant are present in said composition at a ratio of about 1:4. 5. The composition as claimed in any of the preceding claims wherein said enzyme is selected from the group consisting of a-amylase and P-amylase. 6. A method of breaking filter cake deposit formed in oil wells for subsequent removal operations comprising, introducing and circulating through a well bore the composition as claimed in claims 1 to 5. 7. The method as claimed in claim 6, wherein a pre-wash fluid containing an anionic surfactant solution is introduced and allowed to circulate. 8. The method as claimed in claims 6 and 7, wherein said composition is allowed to remain in the wellbore for 24 hours to 128 hours. 9. A composition for breaking filtercake deposit formed in oil wells substantially as herein described with reference to the accompanying drawings. 10. A method of breaking filter cake deposit formed in oil wells for subsequent removal operations substantially as herein described with reference to the accompanying drawings.

Full Text

Technical Field of the Invention
The Invention relates to novel fluids and techniques to optimize/enhance the production of hydrocarbon from subterranean formations, in particular, fluids and techniques are disclosed and claimed which remove wellbore and near-wellbore formation damage in the form of coating formed from drilling and production-related operations; the techniques can be applied either by themselves or in conjunction with other completion operations, such as gravel packing.
Background of the Invention
The present Invention relates to novel fluids and techniques to /optimize/enhance the production of hydrocarbons from subterranean formations. To recover hydrocarbons (e.g., oil, natural gas) it is of course necessary to drill a hole in the subsurface to contact the hydrocarbon-bearing formation. This way, hydrocarbons can flow from the formation, into the wellbore and to the surface. Recovery of hydrocarbons from a subterranean formation is known as "production." One key parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore. Sometimes, the formation rock has a naturally low permeability, other times, the permeability is reduced during, for instance, drilling the well. When a well is drilled, a fluid is circulated into the hole to contact the region of the drill bit, for a number of reasons— including,

f
to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling.
Drilling fluid is expensive particularly in light of the enormous quantities that must be used during drilling. Additionally, drilling fluid can be lost by leaking off into the formation. To prevent this, the drilling fluid is often intentionally modified so that a small amount leaks off and forms a coating on the wellbore, or a "filtercake."
Yet once drilling is complete, and production is desired, then this coating or filtercake must be removed. The present fluids and techniques are directed to removing this filtercake or other such damage in the wellbore and near-wellbore region, that results either intentionally (in the case of drilling fluid) or unintentionally (in the case of scale deposits from produced water or dewatered fluids from workover/stimulation operations performed on the well).
Conventional treatments for removing filtercake include: aqueous solution with an oxidizer (such as persulfate), hydrochloric acid solution, organic (acetic, formic) acid, combination of acid and oxidizer, and aqueous solutions containing enzymes. For instance, the use of enzymes to remove filtercake is disclosed in U.S. Pat. No. 4,169,818, Mixture of Hydroxypropylcellulose and Poly(Maleic Anhydride/Alkyl Vinyl Ether) as a Hydrocolloid Gelling Agent (1979) (col. 1, In. 42); U.S. Pat. No. 3,515,667, Drilling Fluid Additive (1970); U.S. Pat. No. 3,509,950, Well Drilling Mud and Screen Compsition of Use Thereof U.S. Pat. No. 2,259,419, Well Drilling (1941). Chelating agents (e.g., EDTA) are also used to promote the dissolution of calcium carbonate. See, C.N. Fredd and H.S. Fogler,

Chelating Agents as Effective Matrix Stimulation Fluids for Carbonate Formations, SPE 372212 (1997); C.N. Fredd and H.S. Fogler, Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing, SPE 31074 (1996), both articles are hereby incorporated by reference in their entirety. According to conventional teaching, the oxidizer and enzyme attack the polymer fraction of the filtercake; the acids mainly attack the carbonate fraction (and other minerals). Generally speaking, oxidizers and enzymes are ineffective in degrading the carbonate fraction; likewise, acids have very little effect on polymer.
In addition, nimierous problems plague conventional techniques of filtercake removal. Perhaps the most troublesome is the issue of "placement." For instance, one common component in filtercake is calcium carbonate. The substance of choice to remove calcium carbonate is hydrochloric acid . Hydrochloric acid reacts very quickly with calcium carbonate. What happens then, is that the filtercake begins to dissolve, therefore dramatically increasing the permeability of the wellbore face, so that the wellbore region is no longer "sealed off from the formation. Once this happens, the entire clean-up fluid may then leak off into the formation through this zone of increased permeability ("thief zones," or discrete zones within the interval of very high permeability where more filtercake dissolution has occurred than at other places along the interval).
A second problem with removal of filtercake is that it is comprised of several substances, and which are, as mentioned earlier, not generally removable with a single substance. Calcium carbonate and organic polymers (e.g., starch and other polysaccharide) are two primary constituents of conventional drilling fluids that form a filtercake on the

wellbore. Treating these successively—i.e., with two different fluids, one after the other—is problematic since, it requires at least two separate treatments. Combining two different breakers (one for the polymer fraction, one for calcite) is problematic since each has a distinct activity profile (or optimal window of activity, based on temperature, pH, etc.) and the activity profiles of two different breakers may not coincide. This is particularly likely if one of the breakers is an enzyme, which are notoriously temperature and pH sensitive.
Moreover, if the calcium carbonate is removed first— as it often is— then, once the hydrochloric acid contacts the filtercake, regions of higher permeability are created in the wellbore (where the filtercake has dissolved). Hence, fluid will leak-off into the formation during subsequent phases of the filter-cake removal treatment.
Hence, the ideal fluid must be easy to "spot" or place in wellbore over the entire length of the desired zone, contiguous with the producing zone (e.g., a two thousand foot horizontal zone)—before any filtercake dissolution occurs. If the fluid begins to dissolve the filtercake too quickly, then the fluid will be lost through the thief zones and the entire fluid treatment will be destroyed. In other words, a hypothetical ideal fluid would be completely unreactive for a period of time to enable it to be spotted along the entire length of the producing interval, then, once in place, react sufficiently slowly and uniformly, so that no thief zones are. Again, if thief zones form, then the entire mass of fluid can leak off through that zone. Hence, reasonably uniform/controlled dissolution is necessary to ensure that the fluid remains in contact with the filtercake

along the entire interval until near-complete dissolution of the filtercake has occured along the entire interval.
Moreover, removing filtercake is an expensive and time-consuming procedure. Therefore, it is desirable to do this at the same time that another treatment is being performed, if possible. For instance, if a material must be delivered to one portion of the formation into the wellbore (e.g., in conjunction with a remedial treatment), then the fluid used to carry that material can be an acid solution which will also dissolve portions of the filtercake. Again, if the carrier fluid leaks off into the formation through a thief zone, then the remedial operation is completely destroyed.
One common treatment performed on wells, particularly wells in the Gulf Coast region of the United States, is known as a "gravel pack." Gravel pack operations are performed to prevent the production of sand along with hydrocarbon, which often occurs in formations of weakly consolidated sands. To prevent sand production, a filter (or screen) can be placed around the portion of the wellbore in which production occurs. A more long-term solution for sand control is achieved if the region between the screen and the formation is filled with gravel, which is properly sized to prevent the sand from moving through the gravel and into the wellbore—to function as a filter—so that when the sand tries to move through the gravel, it is filtered and held by the gravel or screen, but hydrocarbon continues to flow unhindered (by either the gravel or screen) into the wellbore.
Again, it would be highly advantageous if the fluid used to deliver the gravel could also be used to dissolve the filtercake, which would

iminate the need for a separate treatment just to dissolve the filtercake. his would result in substantial cost savings—both because a separate eatment is costly, and because it take additional time to perform such a eatment.
Thus, what is desired is a fluid that can be used as a carrier fluid hough it need not be used for that purpose) and that can also degrade the Itercake. An ideal carrier fluid is inert— i.e., it should not degrade the ltercake instantaneously (otherwise the fluid can be lost into the prmation)—but an ideal filtercake dissolution fluid must dissolve the ake, eventually. Therefore, an ideal fluid must somehow combine these two contradictory attributes.
Indeed, the need for filtercake clean-up is particularly acute in gravel
ack completions— i.e., wells in which the movement of sand along with
the hydrocarbon is prevented by a gravel pack/screen combination—
lecause, the entrapment of the filter-cake between the formation and
creens or gravel can result in substantial reduction in production. The
beed for a reliable filtercake clean-up treatment with a good diversion
mechanism (to ensure proper placement) is also particularly acute in
horizontal, or highly deviated wells. In these cases, the producing interval
nay be several thousand feet, compared with a vertical well, which may
lave a producing zone of about 30 feet. Because the difficulty of placing a
nass of fluid to achieve near-uniform dissolution over 1000 feet interval is
ar greater than for a 30 feet interval—placement takes longer, and the
potential for the creation of thief zones is far greater.
Therefore, an urgent need exists in the drilling and completions sector for a reliable fluid for degrading filtercake— quickly, efficiently, and

completely, and which can be used as a carrier fluid in conjunction with other completion/workover/stimulation operations. This is the primary objective of the present invention.
Summary of the Invention
The present invention relates to fluids intend to break filtercake (whether produced from drilling, production, completion, workover, or stimulation activity, either produced intentionally or unintentionally. In particularly preferred embodiments, the fluids and techniques are directed to degrading (or "breaking") filtercake formed from starch/carbonate-containing drilling fluid such as the STARDRILLTM (a drill-in fluid manufactured and sold by Schlumberger). In other particularly preferred embodiments, the fluids of the present Invention are operable in conjunction with a gravel pack operation, and in particular, though not exclusively, to break filtercake, in conjunction with a gravel pack operation.
Therefore, one object of the present Invention is to provide novel completion fluids to break filtercake, either alone or in conjunction with other workover/completion/stimulation treatments, but in particular, gravel pack operations. Preferred embodiments relate to fluids to break filtercake having substantial calcite and starch content. Particularly preferred embodiments related to treatment fluids having two essential components; a chelating agent and an enzyme for example a-amylase or P-amylase. These components were selected based on their ability to dissolve different components of the filtercake, and based on their ability to dissolve these components at particular rates relative to one another. Other particularly preferred —

embodiments are fluids having these two components in a VES (viscoelastic surfactant) system. VES systems have niunerous advantages-discussed at length in U.S. Patents incorporated by reference below-including that they are readily gelled, they can be disposed of more easily than guar and modified guar systems, they are more readily removed from subsurface formations. In addition, and of particular importance of the present Invention, VES systems create very low friction pressures compared with conventional carrier fluids, and therefore they are particularly preferred, for instance, in gravel pack operations of the present Invention.
The fluids of the present Invention can be successfully spotted or placed over, for instance, a 2000 ft. horizontal producing zone—without substantial leakoff. Particularly preferred embodiments to achieve this incorporate Mobil's AUPAC" (licensed exclusively to Schlmnberger). This way, the gravel pack operation, for instance, can take place without fluid loss.
At the same time, the fluid of the present Invention acts slowly upon the filtercake, to slowly but steadily dissolve it, but not before the particular workover operation has been completed.
Moreover, the break time (or time to substantial dissolution of the filtercake) of the fluids of the present Invention are optimized so that the overall or blended dissolution rate is very slow at low temperatures but much higher at high temperatures. The primary advantage of this unique temperature-dependence is that fluid can be introduced into the entire zone of interest before filtercake dissolution occurs, then as the fluid

temperature rises due to contact with the wellbore, only then does dissolution occur.
The fluids and techniques of the present Invention are quite general and are operable in a variety of settings. These include, but are not limited to, screen-only completions and gravel pack completions; open hole and cased hole; vertical and highly deviated wells; single-application soak or circulating fluid in which the treatment fluid (of the present Invention) also serves as a carrier fluid for, e.g., a gravel pack operation; In. conjunction with a gelling agent or viscoelastic surfactant (e.g., ClearFRAC'") or alone, and with a variety of clean-up tools. In summary, since the problem of placement and uniform dissolution are present in virtually every instance, the fluids and techniques of the present Invention are readily applicable to any scenario in which it is desirable to remove filtercake from the wellbore or near-wellbore region in the formation, regardless of whether the filtercake was produced during drilling or during other post-drilling operations (e.g., fluid-loss control pill, gravel pack operation, fracturing, matrix acidizing, and so forth).
Finally, the fluids of the present Invention are a viable, cost-effective replacement for HCl-based fluids, conventional fluids of choice to remove filtercake. Perhaps the major problem with HCl systems (aside from their ineffectiveness in removing the carbonate fraction of filtercake) is corrosion—corrosion of the above-ground storage tanks, pumps, down-hole tubulars used to place the fluid, and wellbore casings. Moreover, a cost-effective solution to corrosion is not readily available, as evidenced by the fact that corrosion inhibitors is a significant portion of the total expense of a filtercake remove (or matrix-acidizing) treatment. With

many of the fluids of the present invention (those that do not contain acid) the problem of corrosion is drastically minimized. Additionally, personnel safety and environmental concerns are significantly reduced with the fluids of the present invention.
Accordingly, the present invention provides a composition for breaking filtercake deposit formed in oil wells comprising a viscoelastic surfactant and an enzyme.
Accordingly, the present invention also provides a method of breaking filter cake deposit formed in oil wells for subsequent removal operations comprising, introducing and circulating through a well bore the composition such as herein described.

With reference to the accompanying drawings, in which
Figure 1 shows change in viscosity of various VES solutions at 100 sec' ifter 101 minutes at 180° F, upon addition of K2-EDTA, a-amylase, mmionium persulfate— either separately or in combination. These data show for instance, that the viscosity of VES is not significantly affected by the addition of 0.5% a-amylase, nor is it affected by the addition of 0.5% a-amylase and 28% K2-EDTA.
Figure 2 shows the effect of various combinations of a-amylase and K2-EDTA on VES (5% by volume) rheology: 3% NH4CI and 28% K2-EDTA (diamonds) ; 4% KCl (open boxes); 4% KCl in 28% K2-EDTA (triangles); 3% NH4CI and 0.5% a-amylase and 28% K2-EDTA (diagonal crosses with vertical lines); 3% HN4CI in tap water (diagonal crosses); 3% NH4CI and 0.5% a-amylase (open circles); 4% KCl and 0.5% a-amylase in tap water (venical Hnes); 4% KCl and 0.5% a-amylase in 28% K2-EDTA (light open boxes). These data show, for instance that the addition of a-amylase in a VES solution does not significantly affect VES-solution viscosity at 100 sec', yet if a-amylase is added to a VES solution to which 28% K2-EDTA and KCl are also added, then viscosity is significantly reduced—though not if NH4CI is used instead of KCl.

Figure 3 shows the effect of VES (5%) on the cake-breaking activity of both enzyme and conventional oxidizer breakers. The white bars represent (from left to right): (1) no VES, 0.5% a-amylase, 4% KCl; (2) no VES, 1% ammonium persulfate, 4% KCl. The black bars represent: (1) no VES, 0.5% a-amylase, 4% KCl, (2) VES, 4% KCl; (3) VES 1% ammonium persulfate; (4) VES, 1% ammonium persulfate, 0.1% triethanolamine, 4% KCl. The gray bars represent: (1) VES, 0.5% a-amylase, 28% K2-EDTA, 4% KCl; (2) VES, 28% K2-EDTA, 4% KCl; (3) VES, 1% ammonium persulfate, 28% K2-EDTA, 4% KCl; (4) VES, 5% (low temperature-optimized) ammonium persulfate, 28% K2-EDTA, 4%; (5) VES, 5% encapsulated ammonium persulfate, 28% K2-EDTA, 4% KCl. All assays were conducted at 150° F. These data show that VES impairs but does not entirely destroy cake-breaking activity.
Figure 4 shows the effect of VES (5%) on two breaker types (a-amylase and ammonium persulfate), (1) 1% ammonimn persulfate, no VES (thin gray line); 1% ammoniimi persulfate, VES (think black line); (2) 0.5% a-amylase, no VES (thick gray Hne), 0.5% a-amylase, VES (thick black line). These data show that VES is compatible with these two breaker systems.
Figure 5 shows the effect of VES on K2-EDTA cake-breaking activity, 5% VES, 28% K2-EDTA (light gray line), 5% VES, no K2-EDTA (dark gray line), no VES, 28% K2-EDTA (black line). These data show that the presence of VES substantially affects K2-EDTA activity.

Figure 6 shows the rheology (shear rate versus viscosity) of two different types of VES systems (VES and VESJ, a 28% K2-EDTA/0.5% a-amylase system in 5% VES at 125 °F (light triangles) compared with similar systems, no a-amylase (crosses), 1.5% VES at 75 °F (plus K2-EDTA/a-amylase) (dark triangles), 5% VESi at 140 °F (diamonds). These data show that the rheology of a different VES system is not significantly affected by the addition of K2-EDTA/a-amylase.
Figure 7 is identical to Figure 6 expect that the system was tested at 200° F instead of 125 °F. These data show no significant difference in activity of the systems under study at 125 versus 200° F.
Figure 8 shows the viscosity (at 170 s") of a 3% VES solution at 80° F as a function of HCl concentration. These data show that, above 157o HCl (between 15 and 25%) solution viscosity decreases, but below that, the VES-stability is not affected by the acid.
Figure 9 compares the effect of a-amylase and ammonium persulfate in 5% VES/28% K2-EDTA solutions, 0.5% a-amylase (black line with crosses), no polymer break (gray line), 1% ammonium persulfate (black line). These data show the superior activity of a-amylase over ammonium persulfate in a VES/K2-EDTA system.

Figure 10 compares the effect of different salts on the rheology of a 5% VES + 27.3% K2-EDTA system: 4% potassium chloride (no K2-EDTA) (crosses); 3% ammonium chloride (circles) (no K2-EDTA); 4% potassium chloride (vertical lines); 3% ammonium chloride (flat boxes). These data show that K2-EDTA does not substantially affect the viscosity of the 5% VES system.
Figure 11 shows a comparison of break times (filtercake degradation) for three different systems: 15% HCl (diamonds), 9% formic acid (squares), and 28 % K2-EDTA. These data show that the HCl system breaks the filtercake more rapidly that the other two systems.
Figure 12 shows the effect of a-amylase on a K2-EDTA/VES system on the system's cake-breaking activity. The systems shown are control/blank (diamonds), K2-EDTA/VES only (squares), and K2-EDTA/VES with a-amylase. These data show that the addition of the enzyme substantially enhances leak-off (a proxy for filtercake degradation), and that this effect occurs very quickly ( Figure 13 shows a comparison of two systems with respect to their capacity to break filtercake. The two systems are K2-EDTA only (diamonds) and K2-EDTA, and a-amylase (squares). These data show that more complete break occurs with the K2-EDTA/a-amylase system (after approximately 500 minutes).

figure 14 compares retained permeability for a 5% VES system in 3% TH4CI (2 brs., 300 psi, 150 °F) upon addition of various breakers, from :ft to right: nothing, VES only, 28% K2-EDTA only; 14% K2-EDTA; 28% K2-EDTA at pH 5.5; 28% K2-EDTA + 0.5 a-amylase; and 0.5% -amylase. These data show that the K2-EDTA + a-amylase system gives operior retained permeability.
Detailed Description of the Preferred Embodiments
Again, the center of gravity, though not the exclusive scope, of the resent Invention, is a set of fluid compositions and techniques for emoving de-watered drilling fluid (i.e., "filtercake"). In general, fluids hich perform this function are referred to as "completion fluids." The common denominator of preferred embodiments (completion fluids) of be present Invention is they are specifically, though not exclusively, ptimized to degrade/remove drilling filtercake produced from a certain ind of drilling fluid—a drill-in fluid system, known by the trademark, FARDRILL™. Primary components of STARDRILL are calcite, starch, and lesser concentrations of either xanthan or scleroglucan.
The fluids of the present Invention were designed based on mierous criteria, two primary criteria are: (1) rheology, i.e., ensuring lat the fluid rheology at bottom hole circulating temperature fell with ceptable limits (e.g., sufficient viscosity to deliver gravel) over a wide ear rate range; and (2) clean-up, i.e., ensuring that the formulations were fective at removing filtercake while minimizing damage to the formation

and not unduly interfering with a contemporaneous completion (e.g., gravel pack).
In addition, any system design that combines an enzyme and other breakers must account for the variable activity windows of the different breakers, particularly since some enzymes are highly pH and temperature sensitive.
Example 1 Stability of VES Systems in the Presence of Breakers Again, one object of the present Inveniton is to provide novel fluids that will degrade filtercake and which can also serve as carrier fluids in conjunction with other well treatments, particularly, gravel pack operations. In the case of gravel pack operations, the carrier fluid must be viscous in order to transport the gravel. Thus, VES systems are preferred. Again, VES stands for "viscoelastic surfactant." The use of VES for well treatment fluids has validated in numerous actual well treatments. Well treatment fluids based on VES are the subject of numerous patents and patent applications, each assigned to Schlumberger, and incorporated by reference in its entirety. U.S. Pat. No. 5,258,137, Viscoelastic Surfactant Based Foam Fluids, assigned to Schlumberger Technology Corporation, 1993; U.S. Pat. No. 5,551,516, Hydraulic Fracturing Process and Compositions, Schlumberger Technology Corporation, 1996 ; U.S. Pat. Appl. Ser. No. OS/727,877, Methods of Fracturing Subterranean Formations, assigned to Schlumberger Technology Corporation, filed 9 October 1996; U.S. Pat. Appl. Ser. No. 08/865,137, Methods for Limiting the Inflow of Formation Water and for Stimulating Subterranean

formations, assigned to Schlumberger Technology Corporation, filed 29 May 1997; U.S. Pat. Appl. Ser. No. 09/166,658, Methods of Fracturing tubterranean Formations, assigned to Schlumberger Technology Corporation, filed 5 October 1998.
In the Examples that follow the VES system most often used is N-
is-13-docosenoic-N,N-bis(2-hydroxymethyl)-N-methyl ammonium
hloride (a.k.a. iV-erucyl-Ar,iV-is(2-hydroxyethyl)-7-methyl ammoniimi hloride). In addition, the actual VES system used in the Examples ontains 25% tso-propanol to enhance VES stability at low temperatures, n some instances, a second VES system is used, referred to as VES, and which consists of glyceryl esters of three different fatty acids, 23.5% erucyl C22 with one double bond), 32% oleic (C with one double bond) and W.5% linoleic (Cg with three double bonds separated by methylene groups) acids.
In addition, the VES systems referenced above are fully compatible with seawater in addition to ordinary tap water. Thus, the term "VES" ;ubsumes VES systems prepared from seawater in addition to freshwater. VES systems prepared from seawater are disclosed and claimed in U.S. Pat. A.ppl. Ser. No. 09/166,658, Methods of Fracturing Subterranean Formations, filed 10 October 1998, and assigned to Schlumberger. This appUcation is tiereby incorporated by reference in its entirety, and particularly with respect to that portion disclosing the operabiUty of VES systems prepared from seawater.
The experimental results that follow illustrate that VES systems retain their stability (viscosity) upon addition of the breakers (either alone or in combination) of the present Invention.

The following experimental protocol was observed for the data collected and presented in the Examples that follow. First a dry sandstone core was weighed, then saturated with brine (to water wet the core) and then weighed again. Based on comparison of these two measurements, a pore volune was determined. Next, the core was heated to test temperature (150 °F). Then, 100 pore volumes of kerosene was flowed through the filtercake core, at about 10 psi. The purpose of this step is to fill the pores with hydrocarbon. The sandstone core's permeability to kerosene was then observed. Next, the kerosene is poured off, then 125 ml of STARDRILL drilling fluid was applied to the core under a pressure of 300 psi for about one hour. The goal is simulate overbalanced conditions within a typical wellbore; hence, the STARDRILL fluid was "forced" into the core to mimic leakoff. After one hour, the excess STARDRILL was poured off, and the core was rinsed with brine.
Next, the STARDRILL filtercake-coated core was contacted with a series of "clean-up" solutions— 100 ml, at 300 psi for 2 hours (to simulate, e.g., a typical gravel pack operation). In the case of the data presented in Figure 14, for instance, each clean-up solution consisted of a matrix of 5% VES in 3% NH4CI. These solutions are (from left to right in Figure 14): "backflow" (to simulate allowing the well to produce without any clean¬up) "blank" (VES only), 28% K2-EDTA; 14% K2-EDTA; 28% K2-EDTA at pH5.5; 28% K2-EDTA + 0.5% a-amylase; and 0.5% a-amylase. In each instance, the amount of clean-up solution contacted with the sandstone core was 100 ml. After two hours, the leak-off volumes were observed;

the retained permeability to kerosene was measured at the test temperature.
Upon preparing the breaker systems in the VES matrix, none of the fluids showed sedimentation or phase separation; however, when the pH of the VES in 28% K2-EDTA) was increased to values higher than 11, a white waxy substance was observed. Apparently at this high pH, the EDTA-complex interferes with the surfactants and worm-like micellar structure in the VES system. The viscosity of the systems under study was measured using API Standard ramps at 180F (lOOsec* viscosity). The source of the viscoelastic behavior and the high low-shear viscosity of VES-based solutions is the wormlike micellar structure formed by the surfactants (either 4% KCl or 3% NH4CI). Addition of filtercake-breakers may affect this micellar structure, and hence also the the rheological behavior of the VES solutions. This can occur either through reaction of the additive with the VES-surf actant molecule or by interaction of the additive VES with the ClearFrac™ micellar structure.
The results shall now be discussed. Figure 1 is an overview of the viscosities measured for 5% VES-solutions with various additives. The values correspond to 100 s' after shearing the sample at 100 s" for 101 minutes. This viscosity is calculated from the API-ramps that were taken at that point. These data show for instance that VES viscosity (and probably the microscopic micellar structure) are not significantly affected by the addition of either EDTA or a-amylase, or by the addition of the two breakers together.

Figure 2 reports related data. There, the effect of the addition of starch-breaking enzyme a-amylase on VES rheology is shown. According to Figure 2, addition of a-amylase to a VES-in-brine solution does not significantly affect the viscosity of VES at 100 sec" Yet, when a-amylase is added to VES in EDTA/KCl brine, the viscosity is reduced considerably. It is striking that this effect does not occur if EDTA/NH4CI brine is used. Repetition of both tests gave similar results.
Figure 6 shows the effect on the rheology of VES systems to which 28% K2-EDTA and 4% KCl are added (at 125° F if not specified). These data show that the rheology of VES is not significantly affected by the addition of either K2-EDTA or a-amylase, or both. Figure 7 presents similar data though at higher temperature. In addition what these two Figures also show is that both 5% VES (short-chain) VES at 140° F and 1.5% (long-chain) VES at 75 ° F are competent gravel pack carrier fluids. Hence, in accordance with the present Invention, it is now possible to formulate gravel pack carrier fluids containing filter cake breakers for 125 and 150° F, that have similar rheology.
Figure 8 shows the effect of varying HCl concentration on the viscosity of a 3% VES system at 80° F. As evidenced by these data, viscosity is barely affected from about 5% HCl to about 15% HCl, after which viscosity falls off significantly.
Finally, Figure 10 compares the effect of different salts (sodium salicylate, KCl, and NH4CI) on the rheology of a 5% VES system. These data convincingly demonstrate that K2-EDTA (at up to 28%, which is roughly the solubility Hmit of EDTA in water) does not substantially

affect the viscosity of a 5% VES system. Additionally, these data show that neither KCl nor NH4CI affects the rheology of the 5% VES system; however, soditun saUcylate, even at very low concentrations (0.5%) has a dramatic effect on VES viscosity when EDTA is present (an approximately 40% decrease in viscosity).
From these data, two sets of particularly preferred embodiments emerge. These are completion fluids having both a-amylase and EDTA with or without VES. Yet if VES is used as the matrix, then the preferred salt is NH4CI at about 3%. Thus, one particular preferred completion fluid of the present Invention contains: 5% VES, 0.5% a-amylase, and 28%' K2-EDTA, in a 4% NH4CI solution. Another particular preferred fluid is: , 0.5% a-amylase, and 28% K2-EDTA, in a 4% salt solution (the salt type is less critical if VES is not used).
Without intending to be bound by this suggested mechanism, we posit that the combination of chelating agent and enzyme (e.g., K2-EDTA and a-amylase) operate in synergy to break filer cake comprised of starch and calcite. More particularly, the starch polymer and the calcite are arranged in a complex configuration, e.g., the polymer coating the calcite particles. Thus, a breaker that acts primarily upon the polymer (e.g., an enzyme) will simply degrade the particle coating, but leave the particles untouched. Similarly, a breaker that acts primarily upon the calcite particles will have difficulty reaching them due to the polymer coating— hence the observed synergistic activity of the enzyme + chelating agent combination fluid.

The goal of an ideal completion fluid is that it degrade the filtercake to the greatest extent possible while at the same time ensuring a high retained permeabiHty. Thus, a completion fluid that resulted in maximum filtercake degradation but that left filtercake particles embedded in the wellbore, is ineffective, since retained permeabiHty will be low. Therefore, the degradation must be even and complete— i.e., result in small particles that cannot plug the wellbore, but that can be removed in a circidating wash or can be produced with the hydrocarbon.
Example 2
Breaker Activity in VES systems The previous Example adequately demonstrated that VES systems
are stable—i.e., their viscosity is not substantially affected in the presence
of the breakers of the present Invention (e.g., HCl, formic and acetic acid,
enzymes, and chelating agents). This Example demonstrates that the VES
matrix does not substantially affect the activity of the breakers— i.e., with
respect to breaking filtercake.
Figure 3 shows the effect of VES (5%) on the activity of both enzyme (a-amylase) and conventional oxidizer breakers (ammonium persulfate, dissolved and encapsulated). These data show that VES inhibits the activity of breakers of proven efficacy.
As evidenced by Figure 4, the data presented in Figiire 3 must be qualified by an evaluation of the time-dependence of these systems. Figure 4 shows that VES actually increases the activity of a-amylase over approximately the first 65 minutes of the test.

Figure 5 shows the results of an K2-EDTA system (in the presence if 5% VES and without). These results show that VES does have a ubstantial effect on EDTA activity.
Example 3 Performance of the Completion Fluids of the Present Invention
Having shown that the various breaking agents (e.g., acid, enzymes, nd chelating agents) separately or in combination, are effective in VES Dlutions (as well in non-VES solutions) and having shown to what extent iese agents are affected by the VES, we shall now demonstrate in more etail the superior performance of the completion fluids of the present ivention.
The purpose of this Example is to demonstrate that certain Drmulations of the present Invention exhibit superior filtercake 2moval—compared with conventional systems. The experimental rotocol in this Example was carefully designed to simulate, as closely as ossible, actual conditions in an exemplary water-wet, oil-saturated, mdstone reservoir.
The data presented in Figure 9 compares the effect of a-amylase ersus an oxidizer breaker (ammonium persulfate) in a VES/K2-EDTA astern (5% VES, 28 % K2-EDTA, 4% KCl). These data show that an izyme + EDTA system is unquestionably superior to an oxidizer + DTA system. These data are surprising since, while the EDTA is irected to the calcite fraction of the filtercake, the oxidizer and a-amylase •e directed to the polymer fraction. Therefore, both binary systems are ;omplete" in that they contain a breaker for each of the two fractions

comprising the filtercake, hence one might expect comparable filtercake removal rates (or extent).
Figure 11 presents data that compares the activity (break times) of 15% HCl, formic acid, and 28% K2-EDTA in 5% VES, as a function of temperature. As evidenced by Figure 11, the EDTA system outperforms the acid systems by a substantial margin, particularly at lower temperatures.
Figures 12 and 13 compare the activity of an EDTA system versus an EDTA/a-amylase system, in VES (Figure 12) and without VES (Figure 13). A comparison of the two Figures shows that the EDTA-only system is actually enhanced in the presence of VES, though this effect is imobservable prior to about 90 minutes. Figure 12 corroborates earUer data showing the superior performance of the chelating agent/enzyme system compared with chelating agent by itself. Figure 12 also shows that this effect is very rapid— less than one minute).
The leak-off data of Figure 14 is consonant with that presented in Figure 12. Most significantly though. Figure 14 shows that the EDTA/a-amylase system gives the highest retained permeabiUty—over 90%, compared with the EDTA-only system which resulted in a retained permeabiHty of just over 80%. Therefore, the VES/EDTA/a-amylase system of the present Invention is demonstrably superior to conventional clean-up formulations on both relevant axes of comparison: leak-off and retained permeabiUty. Moreover, results presented earUer (e.g.. Figure 4 for a-amylase; Figure 5 for EDTA) show that VES is a viable carrier fluid for the EDTA/a-amylase system. Similarly, as evidenced by the results

resented in Figures 1 and 2, the EDTA/a-amylase system activity does lot significantly affect the characteristics of the VES matrix (e.g., ascosity).
Finally, the skilled treatment designer will recognize that chelating igents other than EDTA are operable in fluid compositions of the present iivention. The relevant parameters for selection of the fluid are the :alcite (or other mineral) dissolution constant (a thermodynamic )arameter), the proton dissociation constants (also thermodynamic jarameters), and kinetic parameters. The skilled treatment designer can nfer the behavior of other chelating agents by comparing those parameters for EDTA with those for the chelating agent under :onsideration. A systematic study of the kinetics of calcite dissolution by various chelating agents (including EDTA, DTP A, and CDTA) is )resented in C.N. Fredd and H.S. Fogler, The Influence of Chelating Agents m the Kinetics of Calcite Dissolution 204 J. ColHod Interface Sci. 187 (1998). This article is incorporated by reference in its entirety.
Example 4 Specialized Applications The fluids and techniques of the present Invention are quite general md are operable in a variety of settings. Since the problem of placement md imiform dissolution are present in virtually every instance, the flxiids md techniques of the present Invention are readily appHcable to any cenario in which it is desirable to remove filtercake from the wellbore or lear-wellbore region in the formation, regardless of whether the filtercake vas produced during driUing or during other post-drilling operations (e.g..

luid-loss control pill, gravel pack operation, fracturing, matrix acidizing, ind so forth). The fluids and techniques of the present Invention are ippHcable in numerous different environments, including:
• screen-only completions and gravel pack completions;
• open hole and case hole;
• vertical and highly deviated wells;
• single-stage soak fluid or circulating fluid in which the treatment fluid (of the present Invention) also serves as a carrier fluid for, e.g., a gravel pack operation;
• in conjunction with a geUing agent such as a viscoelastic surfactant (e.g., ClearFRAC™) or alone;
• with a variety of clean-up tools and unconventional technologies (e.g., Mobil's Alternate Path Technology, see, e.g., L.G. Jones, et al.y Gravel Packing Horizontal Wellhores With Leak-Ojf Using Shunts, SPE 38640, hereby incorporated by reference in its entirety); or
• in conjimction with other fluid additives (e.g., anti-corrosive agents) or dissolution components (e.g., an oxidizer).
One such specialized setting in which the fluids of the present Invention can be appUed is a particular type of gravel pack operation known as "AllPAC or Alternate Path technology. (As used herein, the term "gravel pack" includes treatments incorporating the AllPAC technology. This technology is described in a number of patents, each is assigned to Mobile, and licensed exclusively to Schlumberger: U.S. Pat. No. 5,560,427, Fracturing and Propping a Formation Using a Downhole Slurry Splitter (1996); U.S. Pat. No. 5,515,915, Well Screen

Having Internal Shunt Tubes (1996); U.S. Pat. No. 5,419,394, Tools for Delivering Fluid to Spaced Levels in a Wellbore (1995); U.S. Pat. No. 5,417,284, Method for Fracturing and Propping a Formation (1995); U.S. Pat. No. 5,390,966, Single Connector for Shunt Conduits on Well Tool (1995); U.S. Pat. No. 5,333,688, Method and Apparatus for Gravel Packing of Wells (1994); U.S. Pat. No. 5,161,613, Apparatus for Treating Formations Using Alternate Flopaths (1992); U.S. Pat. No. 5,113,935, Gravel Packing of Wells (1992); U.S. Pat. No. 5,082,052, Apparatus for Gravel Packing Wells (1992); U.S. Pat. No. 4,945,991, Method for Gravel Packing Wells (1990). Each of these patents is incorporated by reference in its entirety.
The significance of the AllPAC technology to the fluids and techniques of the present Invention cannot be over-emphasized. Without AllPAC, gravel packing with a viscous carrier fluid is very difficult, in some instances, virtually impossible. AllPAC screen is comprised of shimt tubes which permit the easy flow of viscous fluid through the screen annulus to its intended situs.
In addition, a thorough discussion of filtercake removal in conjunction with sand control operations, in open-hole horizontal wells is provided in C. Price-Smith, et. al. Open Hole Horizontal Well Cleanup in Sand Control Completions: State of the Art in Field Practice and Laboratory Development, SPE 50673 (1998). This article is incorporated by reference in its entirety.
The ALLPAC technology incorporates a novel gravel pack screen device which contains "shunt-tubes" or alternate flow paths, attached to the sides of the screen. These shunt tubes permit effective gravel

packing by eliminating bridging (or more precisely, by letting the fluid flow around a bridged zone), thus even long horizontal sections can be gravel packed even with high fluid loss. Therefore, when the fluids of the present Invention are used in conjunction with the ALLPAC technology, a novel method is enabled. In this method, the filtercake is readily cleaned up during the gravel pack operation since fluid loss (leak-off) will not substantially interfere with the quahty of the gravel pack. Thus rig time is substantially reduced by combining filtercake removal with gravel pack treatment.
Indeed, combined gravel pack/filtercake removal treatments the fluids of the present Invention incorporating the AllPAC technology provide a cost-effective means to complete a well. A yard test with a single shunt tube placed in side a slotted liner packed an entire length of 2,000 ft using the VES. During this test, it was foimd that 40/60 gravel (approx. 50 darcies) was sufficient to divert flow down the shunt tube. Again, leak off is not a concern, which is another substantial advantage of the AllPAC technology as it is exploited using the fluids and methods of the present Invention.
Preferably, this composition is allowed to remain in the wellbore for 24 to 128 hours.

WE CLAIM:
1. A composition for breaking filtercake deposit formed in oil wells comprising a viscoelastic surfactant and an enzyme.
2. The composition as claimed in claim 1, wherein said viscoelastic surfactant is N-cis-13-docosenoic-N,N-bis(2-hydroxymethyl)-N-methyl-ammonium-chloride.
3. The composition as claimed in any of the preceding claims wherein said viscoelastic surfactant is present in said composition at a concentration between 0.5% and 7%.
4. The composition as claimed in any of the preceding claims wherein iso-propanol is added and said iso-propanol and said viscoelastic surfactant are present in said composition at a ratio of about 1:4.
5. The composition as claimed in any of the preceding claims wherein said enzyme is selected from the group consisting of a-amylase and P-amylase.
6. A method of breaking filter cake deposit formed in oil wells for subsequent removal operations comprising, introducing and circulating through a well bore the composition as claimed in claims 1 to 5.
7. The method as claimed in claim 6, wherein a pre-wash fluid containing an anionic surfactant solution is introduced and allowed to circulate.

8. The method as claimed in claims 6 and 7, wherein said composition is allowed to remain in the wellbore for 24 hours to 128 hours.
9. A composition for breaking filtercake deposit formed in oil wells substantially as herein described with reference to the accompanying drawings.
10. A method of breaking filter cake deposit formed in oil wells for subsequent
removal operations substantially as herein described with reference to the
accompanying drawings.

Documents:

in-pct-2001-0911-che abstract-duplicate.pdf

in-pct-2001-0911-che abstract.pdf

in-pct-2001-0911-che claims-duplicate.pdf

in-pct-2001-0911-che claims.pdf

in-pct-2001-0911-che correspondence-others.pdf

in-pct-2001-0911-che correspondence-po.pdf

in-pct-2001-0911-che description(complete)-duplicate.pdf

in-pct-2001-0911-che description(complete).pdf

in-pct-2001-0911-che drawings-duplicate.pdf

in-pct-2001-0911-che drawings.pdf

in-pct-2001-0911-che form-1.pdf

in-pct-2001-0911-che form-19.pdf

in-pct-2001-0911-che form-26.pdf

in-pct-2001-0911-che form-3.pdf

in-pct-2001-0911-che form-5.pdf

in-pct-2001-0911-che petition.pdf

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Patent Number

199092

Indian Patent Application Number

IN/PCT/2001/911/CHE

PG Journal Number

30/2009

Publication Date

24-Jul-2009

Grant Date

22-Mar-2006

Date of Filing

29-Jun-2001

Name of Patentee

SOFITECH NV

Applicant Address

RUE DE STALLE 140, B-1180 BRUSSELS,

Inventors:

#	Inventor's Name	Inventor's Address
1	TIBBLES, RAYMOND, J	3511 BATTLE CREEK DRIVE, MISSOURI CITY, TX 77459
2	PALAR, MEHMET	5451 SANTA CHASE LANE, SUGAR LAND, TX 77479
3	CHANG, FRANK, F	7215 EMERALD GLEN DRIVE, SUGAR LAND, TX 77479
4	FU, DIANKUI	1819 BRIGHTLAKE WAY, MISSOURI CITY, TX 77459
5	DAVISON, MARK	MONALTRIE HOUSE, ST. MAMAN ROAD, TORPHINS, ABERDEEN, GRAMPIAN AB31 4JQ
6	MORRIS, ELIZABETH, W, A	137 BLENHEIM PLACE, ABERDEEN, GRAMPIAN, AB25 2DL
7	WIERENGA, ANTJE, M	WALCHEREN 123, NL-3524 ZS UTRECHT
8	VINOD, PALATHINKARA	112 REDBUD DRIVE, POTEAU, OK 74953

PCT International Classification Number

C09K07/02

PCT International Application Number

PCT/2001/911/CHE

PCT International Filing date

1999-12-08

PCT Conventions:

#	PCT Application Number	Date of Convention	Priority Country
1	09/224,440	1998-12-31	U.S.A.