Control of particulate flowback in subterranean wells

Abstract: A subterranean formation is treated with a particulate laden fluid whereby particulate flowback is reduced or prevented. The method includes the steps of providing a fluid suspension including a mixture of a particulate upon which at least a partial coating of a tackifying compound is formed as a result of admixture of the tackifying compound therewith, pumping the suspension into a subterranean formation and depositing the mixture within the formation whereby the tackifying compound retards movement of at least a portion of the particulate within the formation upon flow of fluids from the subterranean formation. The tackifying compound is produced by reaction of a polyacid, polyorganophosphate, polyphosphonate, polysulfate, polycarboxylate or polysilicate, and a metal ion.

Description: This invention relates to a method of treating a subterranean formation to control particulate solids transport during the production of hydrocarbons. Transport of particulate solids during the production of hydrocarbons from a subterranean formation is a continuing problem. The transported solids can erode or cause significant wear in the hydrocarbon production equipment used in the recovery process. The solids also can clog or plug the wellbore thereby limiting or completely stopping fluid production. Further, the transported particulates must be separated from the recovered hydrocarbons adding further expense to the processing. The particulates which are available for transport may be present due to an unconsolidated nature of a subterranean formation and/or as a result of well treatments placing particulates in a wellbore or formation, such as, by gravel packing or propped fracturing. In the treatment of subterranean formations, it is common to place particulate materials as a filter medium and/or a proppant in the near wellbore area and in fractures extending outwardly from the wellbore. In fracturing operations, proppant is carried into fractures created when hydraulic pressure is applied to these subterranean rock formations to a point where fractures are developed. Proppant suspended in a viscosified fracturing fluid is carried outwardly away from the wellbore within the fractures as they are created and extended with continued pumping. Upon release of pumping pressure, the proppant materials remain in the fractures holding the separated rock faces in an open position forming a channel for flow of formation fluids back to the wellbore. Proppant flowback is the transport of proppants back into the wellbore with the production of formation fluids following fracturing. This undesirable result causes undue wear on production equipment, the need for separation of solids from the produced hydrocarbons and occasionally also decreases the efficiency of the fracturing operation since the proppant does not remain within the fracture and may limit the width or conductivity of the created flow channel. Proppant flowback often may be a aggravated by what is described as "aggressive" flowback of the well after a stimulation treatment. Aggressive flowback generally entails flowback of the treatment fluid at a rate of from about 0.001 to about 0.1 barrels per minute (BPM) per perforation of the treatment fluids which were introduced into the subterranean formation. Such flowback rates accelerate or force closure of the formation upon the proppant introduced into the formation. The rapid flowrate can result in large quantities of the proppant flowing back into the wellbore before closure occurs or where inadequate bridging within the formation occurs. The rapid flowback is highly desirable for the operator as it returns a wellbore to production of hydrocarbons significantly sooner than would result from other techniques. Currently, the primary means for addressing the proppant flowback problem is to employ resin-coated proppants or resin consolidation of the proppant which are not capable of use in aggressive flowback situations. Further, the cost of resin-coated proppant is high, and is therefore used only as a tailin in the last five to twenty five percent of the proppant 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 may interact chemically with common fracturing fluid crosslinking systems such as guar or hydroxypropylguar with organo-metallics or borate crosslinkers. This interaction results in altered crosslinking and/or break times for the fluids thereby affecting placement. Another means showing reasonable effectiveness has been to gradually release fracturing pressure once the fracturing operation has been completed so that fracture closure pressure acting against the proppant builds slowly allowing the proppant particles to stabilize before flowback of the fracturing fluid and the beginning of hydrocarbon production. Such slow return is undesirable, however, since it reduces the production from the wellbore until the treatment fluid is removed. In unconsolidated formations, it is common to place a filtration bed of gravel in the near-wellbore area in order to present a physical barrier to the transport of unconsolidated formation fines with the production of hydrocarbons. Typically, such so-called "gravel packing operations" involve the pumping and placement of a quantity of gravel and/or sand having a mesh size between about 10 and 60 mesh on the U.S. Standard Sieve Series into the unconsolidated formation adjacent to the wellbore. It is sometimes also desirable to bind the gravel particles together in order to form a porous matrix through which formation fluids can pass while straining out and retaining the bulk of the unconsolidated sand and/or fines transported to the near wellbore area by the formation fluids. The gravel particles may constitute a resin-coated gravel which is either pre-cured or can be cured by an overflush of a chemical binding agent once the gravel is in place. It has also been known to add various hardenable binding agents or hardenable adhesives directly to an overflush of unconsolidated gravel in order to bind the particles together. U. S. Patents 5,330,005, 5,439,055 and 5,501,275 disclose a method for overcoming the difficulties of resin coating proppants or gravel packs by the incorporation of a fibrous material in the fluid with which the particulates are introduced into the subterranean formation. The fibers generally have a length ranging upwardly from about 2 millimeters and a diameter of from about 6 to about 200 microns. Fibrillated fibers of smaller diameter also may be used. The fibers are believed to act to bridge across constrictions and orifices in the proppant pack and form a mat or framework which holds the particulates in place thereby limiting particulate flowback. The fibers typically result in a 25 percent or greater loss in permeability of the proppant pack that is created in comparison to a pack without the fibers. While this technique may function to limit some flowback, it fails to secure the particulates to one another in the manner achieved by use of resin coated particulates. U.S. Patent 5,501,274, corresponding to the preamble of claim 1, discloses a method for reducing proppant flowback by the incorporation of thermoplastic material in particulate, ribbon or flake form with the proppant. Upon deposition of the proppant and thermoplastic material in the formation, the thermoplastic material softens and causes particulates adjacent the material to adhere to the thermoplastic creating agglomerates. The agglomerates then bridge with the other agglomerates and other particulates to prevent flowback from the formation. It would be desirable to provide a method which will bind greater numbers of particles of the particulate to one another whereby agglomerates may be formed which would further assist in preventing movement or flowback of particulates from a wellbore or formation without significantly reducing the permeability of the particulate pack during aggressive flowback of treatment fluids. We have now devised a method of treating a subterranean formation to inhibit the flow of particulates back through the wellbore with the production of hydrocarbons, without significant effects upon the permeability of the particulate pack. In accordance with the invention, there is provided a method of treating a subterranean formation, which method comprises the steps of: introducing a treatment fluid into a subterranean formation; admixing with at least a portion of said fluid, a particulate which is introduced into and deposited within said fracture; admixing with at least a portion of said particulate a liquid or solution of a tackifying compound produced by the reaction of at least one member selected from the group consisting of polyacids, polyorganophosphates, polyphosphonates, polysulfates, polycarboxylates and polysilicates and a multivalent ion whereby at least a portion of said particulate is at least partially coated by said compound such that the critical resuspension velocity of said at least partially coated particulate is increased by at least 25 percent when tested at a level of 0.5% active material by weight over said particulate alone with water; depositing the tackifying compound coated particulate in the subterranean formation; and flowing back fluid from the formation whereby the tackifying compound coated particulate retards movement of at least a portion of the particulate within said formation. It has also been discovered that the addition of certain surfactants to the fluid suspension facilitates the coating of the tackifying compound upon the particulate. Various surfactants facilitate coating at higher fluid pH, fluid salinity or temperatures. The surfactants are of the following types: nonionics, anionics, cationics and zwitterionics. The coated material is effective in inhibiting the flowback of particulate in a porous pack having a size ranging from about 2 to about 400 mesh in intimate admixture with the tackifying compound coated particulates. The coated material is effective in consolidating particulate in the form of agglomerates in a formation as a result of a fracturing or gravel packing treatment performed on a subterranean formation during aggressive flowback of the treatment fluid. In accordance with the present invention, a liquid or solution of a tackifying compound is incorporated in an intimate mixture with a particulate material such as conventional proppants or gravel packing materials and introduced into a subterranean formation. As used in this specification, the term "intimate mixture" will be understood to mean a substantially uniform dispersion of the components in the mixture. The term "simultaneous mixture" will be understood to mean a mixture of components that are blended together in the initial steps of the subterranean formation treatment process or the preparation for the performance of the treatment process. The coated particulate or proppant material may comprise substantially any substrate material that does not undesirable chemically interact with other components used in treating the subterranean formation. The material may comprise sand, ceramics, glass, sintered bauxite, resin coated sand, resin beads, metal beads and the like. The coated material also may comprise an additional material that is admixed with a particulate and introduced into a subterranean formation to reduce particulate flowback. In this instance the additional substrate material may comprise glass, ceramic, carbon composites, natural or synthetic polymers or metal and the like in the form of fibers, flakes, ribbons, beads, shavings, platelets and the like. In this instance, the additional substrate material generally will be admixed with the particulate in an amount of from about 0.1 to about 5 percent by weight of the particulate. Compounds suitable for use as a tackifying compound comprise a reaction product which when in liquid form or in a solvent solution will form a non-hardening coating, by themselves, upon the particulate and will increase the continuous critical resuspension velocity of the particulate when contacted by a stream of water as hereinafter described in Example I by preferably about 25 percent over the particulate alone when present in a 0.5 percent by weight active material concentration and increase the initial critical resuspension velocity by at least about 40 percent over the particulate alone. Preferably, the continuous critical resuspension velocity is increased by at least 50 percent over particulate alone and most preferably at least about 100 percent over particulate alone and the initial critical resuspension velocity is increased by at least 50 percent and most preferably at least 75 percent over particulate alone. A particularly preferred group of tackifying compounds comprise the reaction products of a polyacid with a multivalent ion such as calcium, aluminium, iron or the like. Such polyacid products include compounds such as mixtures of C 36 dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids which are reacted with polyamines. Other polyacids indude trimer acids, synthetic acids produced from fatty acids, maleic anhydride and acrylic acid and the like. Such acid compounds are available from companies such as Witco, Union Camp, Chemtall, and Emery industries. The reaction products are available from, for example, Champion Chemicals, Inc. and Witco. Similarly, various polyorganophosphates, polyphosphonates, polysulfates, polycarboxylates, or polysilicates may be reacted with a multivalent ion to yield a tackifying compound. If retardation of the rate of reaction is desired, esters of the above compounds may be utilized which will then react with the multivalent ion as the esters hydrolyze at the subterranean formation temperatures in the treatment fluids. Alternatively, chelates may be formed with known chelating agents such as citric acid, hydroxypropionates and the like to retard the rate of reaction. Further, it has been found possible to generate the tackifying compound in-situ within the subterranean formation by introduction of the polyacid to contact multivalent ions present in the treatment fluid within the subterranean formation. The multivalent ions may be either naturally occurring in the formation or introduced with the treatment fluid. The tackifying compound is admixed with the particulate in an amount of from about 0.1 to about 3.0 percent active material by weight of the coated particulate. It is to be understood that larger quantities may be used, however, the larger quantities generally do not significantly increase performance and could undesirably reduce the permeability of the particulate pack. Preferably, the tackifying compound is admixed with the particulate introduced into the subterranean formation in an amount of from about 0.25 to about 2.0 percent by weight of the coated particulate. When the tackifying compound is utilized with another material that is to be admixed with the particulate and which is to be at least partially coated with the tackifying compound, such as glass fibers or the like, the compound is present in an amount of from about 10 to about 250 percent active material by weight of the glass fibers or other added material and generally from about 0.1 to about 3 percent active material by weight of the quantity of particulate with which the coated material is intimately admixed. Preferably the tackifying compound is present in an amount of from about 50 to about 150 percent of the material which is to be at least partially coated with the tackifying compound and then added to the particulate. At least a portion of the tackifying compound introduced with the additional material will contact and coat at least a portion of the particulate with which it is admixed. The liquid or solution of tackifying compound interacts mechanically with the particles of particulate introduced into the subterranean formation to limit or prevent the flowback of particulates to the wellbore. The liquid or solution of tackifying compound generally is incorporated with the particulate in any of the conventional fracturing or gravel packing fluids comprised of an aqueous fluid, an aqueous foam, a hydrocarbon fluid or an emulsion, a viscosifying agent and any of the various known breakers, buffers, surfactants, clay stabilizers or the like. Generally the tackifying compound may be incorporated into fluids having a pH in the range of from about 3 to about 12 for introduction into a subterranean formation. The compounds are useful in reducing particulate movement within the formation at temperatures from about ambient to in excess of 275°F. It is to be understood that not every tackifying compound will be useful over the entire pH or temperature range but every compound is useful over at least some portion of the range and individuals can readily determine the useful operating range for various products utilizing well known tests and without undue experimentation. It has been discovered that the incorporation of or addition of certain surfactants to the fluid suspension can improve or facilitate the coating of the tackifying compound upon the particulate. The addition of selected surfactants has been found to be beneficial at both elevated fluid salinity and elevated fluid pH as well as at elevated temperatures. The surfactants appear to improve the wetting of the particulates by the tackifying compound. Suitable surfactants include: nonionics, such as, long chain carboxylic esters such as propylene glycol, sorbitol and polyoxyethylenated sorbitol esters, polyoxyethylenated alkylphenols, alkyphenol, ethoxylates, alkylglucosides, alkanolamine condensates and alkanolamides; anionics such as, carboxylic acid salts, sulphonic acid salts, sulfuric ester salts and phosphonic and polyphosphoric acid esters; cationics, such as, long chain amines and their salts, quaternary ammonium salts, polyoxyethylenated long chain amines and quaternized polyoxyethylenated long chain amines; and zwitterionics, such as n-alkylbetaines. The liquid or solution of tackifying compound generally is incorporated with the particulate as a simultaneous mixture by introduction into the fracturing or gravel packing fluid along with the particulate. Fracturing fluids are introduced into the subterranean formation at a rate and pressure sufficient to create at least one fracture in the formation into which particulate then is introduced to prop the created fracture open to facilitate hydrocarbon production. Gravel packing treatments generally are performed at lower rates and pressures whereby the fluid can be introduced into a formation to create a controlled particule size pack surrounding a screen positioned in the wellbore without causing fracturing of the formation. Alternatively the gravel pack may be performed without a screen and the pack may fill the wellbore. Thereafter, the pack may be drilled out or reamed to open a passage in the bore. The particulate pack surrounding the wellbore then functions to prevent fines or formation particulate migration into the wellbore with the production of hydrocarbons from the subterranean formation. The tackifying compound may be introduced into the fluid before, after or simultaneously with introduction of the particulate into the fluid. When the tackifying compound is generated in-situ in the formation the reactants may be introduced individually as previously described above for the tackifying compound and the multivalent ion source may be naturally occurring or introduced into the formation. The liquid or solution may be incorporated with the entire quantity of particulate introduced into the subterranean formation or it may be introduced with only a portion of the particulate, such as in the final stages of the treatment to place the intimate mixture in the formation in the vicinity of the wellbore. For example, the tackifying compound may be added to only the final 20 to 30 percent of the particulate laden fluid introduced into the formation. In this instance, the intimate mixture will form a tail-in to the treatment which upon interaction within the formation with the particulate will cause the particles to bridge on the agglomerates formed therein and prevent movement of the particles into the wellbore with any produced fluids. The tackifying compound may be introduced into the blender or into any flowline in which it will contact the material to be at least partially coated by the compound. The compound may be introduced with metering pumps or the like prior to entry of the treatment fluid into the subterranean formation. In an alternate embodiment, the particulate may be premixed with the tackifying compound prior to admixing with a treatment fluid for use in a subterranean formation. Reference is made hereafter to the accompanying drawing (Figure 1) which provides a schematic illustration of the test apparatus utilized to determine the critical resuspension velocity for a coated substrate material. To further illustrate the present invention and not by way of limitation, the following Examples are provided. EXAMPLE 1 The evaluation of a liquid or solution of a compound for use as a tackifying compound is accomplished by the following test. A critical resuspension velocity is first determined for the material upon which the tackifying compound is to be coated. Referring now to Figure 1, a test apparatus is illustrated for performing the test. The apparatus comprises a ½" glass tee 10 which is connected to an inlet source 12 of water and an outlet 14 disposal line is blocked to fluid flow. A water slurry of particulate is aspirated into the tee 10 through inlet 12 and collected within portion 16 by filtration against a screen 18. When portion 16 of tee 10 is full, the vacuum source is removed and a plug 20 is used to seal the end of portion 16. The flow channel from inlet 12 to outlet 14 then is swabbed clean and a volumetrically controlled pump, such as a "MOYNO" pump, is connected to inlet 12 and a controlled flow of water is initiated. The velocity of the fluid is slowly increased through inlet 12 until the first particule of particulate material is picked up by the flowing water stream. This determines the baseline for the starting of the resuspension velocity. The flow rate then is further increased until the removal of particles becomes continuous. This determines the baseline for the continuous resuspension velocity. The test then is terminated and the apparatus is refilled with particulate having a coating corresponding to about 0.5 percent active material by weight of the particulate applied thereto. Similar trends generally are seen in the results when the concentrations tested are from about 0.1 to about 3 percent, however, the 0.5 percent level which is within the preferred application range is preferred for standardization of the procedure. The test is repeated to determine the starting point of particulate removal and the velocity at which removal becomes continuous. The percent of velocity increase (or decrease) then is determined based upon the initial or continuous baseline value. The results of several tests employing the preferred polyamide of the present invention, and conventional epoxy and phenolic resins known for use in consolidation treatments in subterranean formations with 20/40 mesh sand are set forth below in Table I. Test No. Particulate Size Coating Agent, % V/Wt Particulate Percent Of Velocity Change At Starting Continuous 1 20/40/mesh sand none 0 0 2 20/40 mesh sand 1/2 percent polyamide 192 222 3 20/40 mesh sand 1 percent polyamide 271 391 4 20/40 mesh sand 1/2 percent phenolic -0.5 6.5 5 20/40 mesh sand 1 percent phenolic -9 -6.8 6 20/40 mesh sand 1/2 percent epoxy -9 -1.2 7 20/40 mesh sand 1 percent epoxy 5.2 12.2 The data clearly illustrates the substantial increase in the critical resuspension velocity of a particulate coated with the tackifying compound in comparison to other known formation consolidation agents which require hardening to be effective. EXAMPLE II The test procedure of Example I is utilized to determine the efficacy of a tackifying compound produced by the reaction of a polyacid with a multivalent ion. The polyacid comprised a commercially available mixture of C 36 dibasic acids and the multivalent ion was aluminum. The reaction was effected by admixing the constituents at ambient temperature and pressure. Thereafter a quantity of the reaction product was admixed with 20/40 mesh sand in an amount of 1/2% V/wt particulate and introduced into the test apparatus after determination of a baseline. The results are set forth in Table II, below. Coating Agent Percent of Velocity Change At: Starting of Sand Particle Transport Continuous Sand Particle Transport None 0 0 Polyacid reaction product 22 46 The data indicates that a polyacid may be reacted with a multivalent ion to form a reaction product suitable for use as a tackifying compound. While the present invention has been described with regard to that which is currently considered to comprise the preferred embodiments of the invention, other embodiments have been suggested and still other embodiments will occur to those individuals skilled in the art upon receiving the foregoing specification. It is intended that all such embodiments shall be included within the scope of the present invention as defined by the claims appended hereto.

Claims: A method of treating a subterranean formation, which method comprises the steps of: introducing a treatment fluid into a subterranean formation; admixing with at least a portion of said fluid, a particulate which is introduced into and deposited within said fracture; admixing with at least a portion of said particulate a liquid or solution of a tackifying compound whereby at least a portion of said particulate is at least partially coated by said compound such that the critical resuspension velocity of said at least partially coated particulate is increased by at least 25 percent when tested at a level of 0.5% active material by weight over said particulate alone with water; depositing the tackifying compound coated particulate in the subterranean formation; and flowing back fluid from the formation whereby the tackifying compound coated particulate retards movement of at least a portion of the particulate within said formation, characterised in that the tackifying compound is produced by the reaction of at least one member selected from the group consisting of polyacids, polyorganophosphates, polyphosphonates, polysulfates, polycarboxylates and polysilicates and a multivalent ion. A method according to claim 1, wherein said tackifying compound is admixed with said particulate in an amount of from 0.1 to 3.0 percent by weight of said particulate. A method according to claim 1 or 2, wherein said treatment fluid includes nonionic, cationic, anionic or zwitterionic surfactant, or any mixture of two or more thereof. A method according to claim 1, 2 or 3, wherein said coated particulate has a critical resuspension velocity in excess of 50 percent over said particulate alone. A method according to claim 1, 2, 3 or 4, wherein said tackifying compound comprises the reaction product of a liquid, or solution of a, polyacid and a multivalent ion. A method according to claim 5, wherein said multivalent ion is aluminium, calcium or iron. A method according to any of claims 1 to 6, wherein said particulate comprises at least one of sand, ceramic particles, resin coated sand, hardened resin beads, sintered bauxite, metal particles, glass particles. A method according to any of claims 1 to 7, wherein the treatment fluid also includes a particulate material which is metal, a natural or synthetic polymer, a ceramic or glass. A method according to claim 3, wherein said surfactant comprises at least one member selected from alkylglucosides, long chain carboxylic esters, sorbitol, polyoxyethylenated sorbitol esters, polyoxyethylenated alkylphenols, alkylphenols, ethoxylates, alkanolamine condensates, alkanolamides, carboxylic acid salts, sulphonic acid salts, sulfuric ester salts, phosphonic acid esters, polyphorphoric acid esters, long chain amines, long chain amine salts, quaternary ammonium salts, polyoxyethylenated long chain amines, quatemized polyoxyethylenated long chain amines and alkylbetaines.

Inventors: DEWPRASHAD BRAHMADEO, NGUYEN PHILIP D, STANFORD JAMES R, WEAVER JIM D, DEWPRASHAD, BRAHMADEO, NGUYEN, PHILIP D., STANFORD, JAMES R., WEAVER, JIM D.
Applicants: HALLIBURTON ENERGY SERV INC, HALLIBURTON ENERGY SERVICES, INC.
Application year: 1997
Main classification: E21B43
IPC codes: C09K8