Abstract:
A method of treating a subterranean formation penetrated by a wellbore to mitigate the production of unwanted fluids from the wellbore is carried out by forming a treatment fluid containing at least one of an oil-wetting or water-repelling surfactant and a carrier fluid. The treatment fluid is then introduced into the wellbore. The treatment or treatments may be performed remedially or prophylacticaly. The treatment may include the completion and production of zones containing the undesirable fluid(s) and the deliberate formation of cones therein.

Description:
BACKGROUND 
     The statements in this section merely provide background information related to the present disclosure and may not constitute prior art. 
     Coning in wells is a common problem which includes, but is not limited to, water coning and gas coning. Water coning in oil wells occurs when the water beneath an oil-bearing zone encroaches the oil-bearing zone. This may be due to the rate of oil extraction or “drawdown” that results when the oil is being produced. The water may enter the well perforations so that it is produced with the oil. Eventually, the water encroachment may be significant enough so that very little or no oil is produced. Gas coning can also be a problem in oil and water wells. Gas coning is based upon the same principles as water coning. Gas can cone downward and occlude the perforations decreasing and eventually preventing liquid production. 
     In many oil and gas fields, water production may exceed oil production. In some of these areas, reservoir drive is low and total reservoir fluid production may be less than 100 bpd (&lt;15.9 m 3 /day). Many depleted reservoirs may fall into this category. Wells under these conditions often do not have the economic potential to support the cost of water control remediation/intervention services as they exist today. High oil extraction rates, in otherwise productive wells, may also result in undesirable water production. 
     Efforts to preempt or postpone water production typically involve perforating the wellbore as far above the water-bearing zone as possible and producing oil below the critical oil production rate. In many instances, producing below the critical oil rate may be uneconomical. This was first described by Muskat and Wyckoff. See Muskat, M. and Wyckoff, R. D.: “ An Approximate Theory of Water - Coning in Oil Production,” Trans . AIME (1935). Johns et al more recently presented an improved treatment of this problem providing analytical solutions for cases of both upward and downward coning (SPE 77772). 
     Current methods used to prevent or reduce unwanted fluid production include injecting a “blocking” or “plugging” agent that effectively blocks off or seals the undesirable fluid zone. Various polymers and gels have been used for this purpose. Blocking agents may be injected into the formation in a non-swollen or a non-precipitated state. In the case of water coning, the blocking materials will swell or precipitate, thus plugging or blocking off the area from further water influx. When treating gas coning, foamed gels have been used. The use of these materials may have some disadvantages, however. Such treatments may be rather costly and it is difficult to place the blocking materials to sufficiently seal off a large enough area around the wellbore for them to be effective. Furthermore, the blocking treatment may be ineffective when fissures or fractures are present in the formation. If clean-up of the materials is necessary, these materials may be difficult to remove. And in some cases, these materials may inadvertently result in permanent blocking or plugging of the desired production zone. 
     Because of the shortcomings of these various methods, new methods and improvements to control unwanted fluid flow from subterranean formations are needed. 
     SUMMARY OF THE INVENTION 
     This invention relates to a method of reducing the deleterious effects of undesirable fluids, such as aqueous fluids, in a subterranean formation by placing an oil-wetting or water-repelling surfactant, in the formation. 
     Disclosed are methods of treating a subterranean formation penetrated by a wellbore, the method serving to mitigate the production of undesirable fluids from a wellbore. In one aspect, the methods include producing an undesirable fluid from a zone predominantly containing the undesirable fluid so as to form a cone from a zone predominantly containing desirable fluid into the zone predominantly containing the undesirable fluid; forming a treatment fluid comprising a carrier fluids and at least one of an oil-wetting or water-repelling surfactant, and then introducing the treatment fluid into the wellbore; and, subsequently producing from the zone predominantly containing the desirable fluid. 
     In one embodiment, the treatment fluid may be introduced into the zone predominantly containing the desirable fluid prior to producing the undesirable fluid from the zone predominantly containing the undesirable fluid so as to form a cone from the zone predominantly containing the desirable fluid into the zone predominantly containing the undesirable fluid. In another embodiment, the treatment fluid is introduced into the zone predominantly containing the undesirable fluid prior to producing the undesirable fluid from the zone predominantly containing the undesirable fluid so as to form a cone from the zone predominantly containing the desirable fluid into the zone predominantly containing the undesirable fluid. 
     In accordance with the invention, the carrier fluid may be a gas, crude oil, mineral oil, aqueous fluids, emulsions, non-aqueous fluids in which the oil-wetting or water-repelling surfactants are soluble, non-aqueous fluids that do not substantially alter surface wettability from generally neutral to oil wet, and non-aqueous fluids in which the oil-wetting or water-repelling surfactants are dispersible. In some cases, an overflush of one or more of an aqueous fluid or non-aqueous fluid containing substantially no oil-wetting or water-repelling surfactant may be introduced into the formation following introduction of the treatment fluid. Blocking agents may also be injected into the wellbore following introduction of the treating fluid. 
     In some aspects, the treatment fluid is an aqueous fluid and the surfactant is present in the treatment fluid in an efficacious amount, such as from about 1 or more times the critical micelle concentration (CMC) of the surfactant for the aqueous fluid, and preferably in an amount of from about 5 to about 50 times above the critical micelle concentration (CMC) of the surfactant for the aqueous fluid. 
     In many embodiments, the well is shut in for a period sufficient to accomplish the required alteration of the formation treated. For example, following the introduction of the treatment fluid, the well is shut-in for a time from about 12 hours to about 2 weeks prior to producing the wellbore. 
     In yet other aspects, methods of the invention may further include introducing an acidizing fluid into the formation through the wellbore and removing at least a portion of the acidizing treatment fluid through the wellbore after a preselected period of time prior to introducing the treatment fluid into the wellbore. 
     According to the invention, subsequent to introduction of the treatment fluid, fluids produced from the wellbore may be monitored for surfactant content and then the well retreated with a second treatment fluid when the surfactant content of the produced fluids reaches a preselected level. 
     Other embodiments of the invention include methods of treating a subterranean formation penetrated by a wellbore to mitigate the production of undesirable fluid from the wellbore, where prior to producing fluids from the wellbore, a treatment fluid comprising a carrier fluid at least one of an oil-wetting or water-repelling surfactant is introduced into the wellbore, and then the well is subsequently produced. Here, an optional postflush following the treatment fluid introduction may be conducted. Also, an overflush of at least one of an aqueous fluid or non-aqueous fluid containing substantially no oil-wetting or water-repelling surfactant may be introduced into the formation following introduction of the treatment fluid. Following the introduction of the treatment fluid, the well may be shut-in for a time from about 12 hours to about 2 weeks prior to producing the wellbore. 
     In yet another embodiment, a method of treating a subterranean formation penetrated by a wellbore to mitigate the production of undesirable fluid(s) from the wellbore is given, where a cone of the undesirable fluid exists in the zone predominantly containing the desirable fluid, where the method includes forming a treatment fluid comprising a carrier fluid and at least one of an oil-wetting or water-repelling surfactant and introducing the treatment fluid into the wellbore, then subsequently producing the well. 
     Also, the invention includes treatment methods where a subterranean formation contains a fracture that extends toward an aqueous-bearing portion of the formation, where a treatment fluid containing a carrier fluid and at least one of an oil-wetting or water-repelling surfactant is prepared and introduced into the fracture. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which: 
         FIG. 1  is a schematic showing two interfacing immiscible fluids within a capillary tube; 
         FIG. 2  is a schematic showing a capillary system for use in testing surfactants for use in treating a subterranean formation in accordance with the invention; 
         FIG. 3  is a schematic of the system of  FIG. 2 , illustrating different fluid pressures within the system; 
         FIG. 4  is a schematic showing the system of  FIG. 2  after a treatment surfactant has been introduced, illustrating the effect of reducing the capillary pressure; 
         FIG. 5  is a schematic showing water coning in a well prior to treatment carried out in accordance with the invention; and 
         FIG. 6  is a schematic showing the well of  FIG. 5  after a remedial treatment is carried out in accordance with the invention, wherein down coning of hydrocarbons into the water zone creates blockage to aid in the prevention of water production. 
     
    
    
     DETAILED DESCRIPTION 
     At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer&#39;s specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. 
     It should be noted that description and examples are presented solely for the purpose of illustrating the preferred embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. While the compositions of the present invention are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already cited. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range. 
     This invention relates to a method of reducing the deleterious effects of undesirable fluids, such as aqueous fluids, in a subterranean formation by placing an oil-wetting or water-repelling surfactant, in the formation. Capillary pressure in subterranean formations may aid in the influx of undesirable fluids, and it has been discovered that by changing the wettability of the formation to manipulate the capillary pressure, the movement of undesirable fluids can be reduced or eliminated.  FIG. 1  shows the interface of two immiscible fluids in a capillary tube. The capillary pressure is defined as the pressure difference between two interfacing immiscible fluids in static equilibrium and may be represented by the Equation (1) below:
 
 P   c   =P   nw   −P   w    (1)
 
where,
 
     P c =the capillary pressure; 
     P nw =the pressure of the non-wetting fluid; and 
     P w =the pressure of the wetting fluid. 
     The capillary pressure is also related to the contact angle, θ, ( FIG. 1 ) between the liquid interface and the capillary, which is given by the Young-Laplace equation represented by Equation (2) below:
 
 P   c =2γ·cos θ/ r    (2)
 
where,
 
     γ=the interfacial tension between the wetting and non-wetting fluids; 
     θ=the contact angle; and 
     r=the effective radius of the capillary. 
     Accordingly, it is well established that by changing the contact angle, the capillary pressure can also be changed. It is also well established that the capillary pressure can be changed by manipulating interfacial tensions. The most common method for changing interfacial tension is by adding surfactants to one or both of the fluids. 
     The surfactant absorption is dependent upon the rock properties of the formation being treated and may vary according to the cation exchange capacity (CEC), the pH of the applied treatment, the rock type, the average surface area to volume ratio, the amount and type of clay minerals, the ionic makeup of the pore fluid and the ionic makeup of the treatment fluid. 
     Many surfactants will decrease the interfacial tension from about 10% to 65%, but will not alter the contact angle substantially. In contrast, those surfactants that can attain a neutral wettability, as evidenced by changing the contact angle to about 70° to 110°, will lower the capillary pressure by two mechanisms—interfacial tension and wettability. 
     In order to determine the suitability of a surfactant in altering the surface of the formation pores and channels, a simple experiment can be conducted. A simple testing apparatus, such as that shown in  FIG. 2 , may be used for evaluating surfactants. The apparatus consists of a fluid container  10 , which may be in the form of a beaker, bottle or test tube, a capillary tube  12 , an upper fluid reservoir  14  with a plunger  16  and a three-way stopcock  18 . This apparatus provides a simple model of a reservoir system. The three-way valve  18  provides a convenient method of controlling the fluid flow and column height, and also allows trapped air to be removed from the system. A cathetometer or other measuring device (not shown) may be used or provided with the apparatus to measure fluid height, etc. 
     The capillary tube  12  should have a diameter small enough to result in an appreciable rise in the wetting fluid  20 . Capillary diameters of 0.5 to 1 mm have been found to be suitable. These sizes result in a water rise of about 2.3 in. (5.84 cm) and about 1.15 in (2.92 cm), respectively. The material of the capillary may be glass. This will provide a suitable simulation for formations composed of siliceous materials. Other materials of the capillary tube may also be used to simulate materials of the formation to be treated. 
     A side inlet  22  is provided to simulate the bottom of the wellbore or a perforated area and allows air to be bleed from the system, if necessary. The valve  18  allows the inlet  22  to be selectively opened or closed. 
     In carrying out tests using the apparatus, the capillary tube may be cleaned to remove contaminants or other residue. Soaking the capillary tubes in hot nitric acid for about 5 minutes has been found to be effective in cleaning the tube surfaces. The tubes are then dried. Other components, such as the container  10  for holding the test fluid, may be cleaned in a similar manner, as well. 
     A test using the desired surfactant-free fluid may initially be used for the capillary test to provide a baseline. The container  10  is filled with the fluid and the capillary  12  is lowered into the fluid  20 , with the side inlet  22  open to the capillary tube  12  to bleed off air. The fluid should tend to rise within the capillary. Any air bubbles within the capillary should be removed by raising the capillary up and slowly lowering it into the solution  20 . If this is unsuccessful in removing the air bubbles, the capillary should be washed again in hot nitric acid solution to clean the walls of the tube. 
     To ensure that the column of test fluid within the capillary is at equilibrium, with the inlet  22  closed, suction or pressure to may be applied to move the column away from equilibrium. This may be accomplished by manipulating the piston  16  of the reservoir  14 , which is coupled to the capillary. The valve  18  allows for the adjustment of the level of fluid height within the capillary. The upper reservoir  14  is filled with a fluid that is non-miscible with the test fluid and non-wetting to the glass surface. Air provides the most convenient non-miscible, non-wetting fluid for use with the testing apparatus, although other fluids may also be used. When a gas is used as the non-wetting fluid, the ideal gas law, and any refinements thereof, may be used to approximate the change in pressure resulting from a change in volume caused by displacement of the piston. In an actual reservoir, the position of the impermeable barrier is fixed, however, and only the level of water in the capillary changes, i.e. the position of the transition zone changes. 
     After the column of test fluid has been moved away from equilibrium, it is allowed to re-achieve equilibrium. The height of the column of the test fluid in the capillary above the fluid level in the container is then measured. This procedure may be repeated several times to ensure consistent results. Means to enhance the accuracy of the measurement, such as a cathetometer, can be employed. 
     Once the baseline has been established, the surfactant to be tested is added to treat the surfaces of the capillary. This may be done by adding the surfactant directly to the water already in the container and then mixing it thoroughly. Alternatively, the surfactant may be injected into the capillary itself. 
     Another test with the surfactant or wettability altering material, which shall be hereinafter referred to as the “Capillary Pressure Test,” is then conducted, as previously described for the deionized water, to provide a baseline for the surfactant being evaluated. A suitable surfactant will result in a drop in capillary pressure for the surfactant, which is determined by a decrease in the measured height of the interface at equilibrium. 
     Suitable surfactants may be selected based upon several selection criteria. Surfactants may be initially selected from those that lower the capillary pressure in the Capillary Pressure Test. Those surfactants that meet this initial criteria may then be tested to see if they show good persistence by exhibiting a reduced capillary pressure after flushing with three (3) pore volumes of brine. Further criteria for selection of surfactants may include surfactants that have a solubility of from about 5 to 50 times the critical micelle concentration (CMC), surfactants that show capillary pressure lowering at low effective concentrations, those that are environmentally friendly and those that have good physical properties to facilitate the handling and application. 
     Wettability can also be measured using formation rock, but the technique is very tedious and requires careful attention to detail. Reference: Donaldson, E. C., Thomas, R. D. and P. B Lorenz: “Wettability Determination and its Effect on Recovery Efficiency,”  SPEJ  (March 1969) 13-20. Reference: Amott, Earl: “Observations Relating to the Wettability of Porous Rock”, Trans. AIME-(1959) Vol. 216, 156-162. 
     In an actual reservoir, which is typically a reservoir system with low vertical permeability, the position of the upper impermeable barrier remains fixed. Only the level of water in the formation (or capillaries) changes, i.e. the position of the transition zone changes. It is apparent that the level of water in the capillary will change as the pressure in the reservoir, P r , changes. During production, the pressure in the reservoir will decline, and water will move upward in response. 
     The difference between the reservoir pressure (P r ) and the flowing bottomhole pressure (P wb ) is referred to as “drawdown.” This is the driving force that forces fluids from the reservoir into the wellbore. As used herein, “P a ” refers to the pressure in the reservoir at the aquifer oil-water contact a sufficient distance away from the cone of water so as not to be influenced by the cone. To demonstrate how capillary pressure reduces drawdown required for water influx reference is made to  FIG. 3 , which shows different fluid pressures in the testing apparatus.  FIG. 3  shows a simple diagram that may be used to determine the drawdown required for water to be raised to the level of the lowest perforation, represented by inlet  22 . The pressure at the lowest perforation is P wb , i.e. the wellbore pressure at that depth. The following illustrates how a high capillary pressure, P c , reduces the allowable drawdown, as illustrated by Equation (3) below:
 
 P   a   −P   wb   +P   c &gt;ρ w   gl    (3)
 
where,
         P a =the aquifer pressure;   P wb =the wellbore pressure;   P c =the capillary pressure;   ρ w =density of the wetting fluid;   g=gravity (9.8 m/s 2  or 32.17 ft/s 2 ); and   l=distance from the oil-water contact in the absence of coning to the lowest perforation.       

     In order for water to be raised to the level of the lowest perforation, the following applies:
 
 P   nw   −P   wb &gt;ρ w   g ( l−y )   (4)
 
where,
 
     P nw =the pressure of the non-wetting fluid; 
     ρ w =the density of the wetting fluid; and 
     y=the capillary height of the wetting fluid. 
     From Equation (1) above it follows that:
 
 P   c   +P   w   −P   wb &gt;ρ w   g ( l−y )   (5)
 
     It also follows that:
 
 P   w   =P   a −ρ w   gy    (6)
 
     so that:
 
 P   c   +P   a −ρ w   gy−P   wb &gt;ρ w   g ( l−y )   (7)
 
     From the above, it can be seen that reducing, eliminating or even making the capillary pressure negative will allow greater drawdown, while avoiding the production of water. 
       FIG. 4  depicts what may be expected following treatment of a reservoir to alter the relative permeability of an area near the well bore. After treating with a suitable surfactant solution, the surfactant will alter the mineral surface in the zone of contact to change the contact angle of the wetting fluid, as is shown. In this case, the formation has been altered by the surfactant to be strongly oil wet. The actual alteration could also be neutral-wet to oil-wet. By changing the wettability or contact angle the capillary pressure is also reduced, or, in this case, is actually negative. As seen from the equations presented above, this immediately allows a higher drawdown. Before water can be produced, the drawdown pressure must exceed the hydrostatic pressure plus the capillary pressure or:
 
 P   a   −P   wb &gt;ρ w   gl+P   c    (8)
 
     As previously discussed, the above Capillary Pressure Test may be used in selecting appropriate surfactants or materials for use in altering the wettability of the formation surfaces to reduce the capillary pressure. The materials should be readily soluble or dispersible in water or other aqueous carrier fluid. A number of materials such as asphaltenes and resins will change the surface wettability to oil-wet state. However, these materials are not water soluble and cannot be transported through the water cone easily. Optionally, the surfactant may be selected to be environmentally friendly and have a suitable pour point at temperatures that may be encountered during use, e.g. a pour point of around −10° F. (−23.3° C.) or lower. In addition, the selected material should have a flash point above 100° F. (37.8° C.) and preferably above 140° F. (60° C.) for safe handling. 
     Cationic, anionic, non-ionic or zwitterionic surfactants or combinations of these may be used, provided they alter the capillary pressure as described previously. The most efficacious treatment might be different from well to well, even in the same reservoir, as the diagenetic history might be different. The optimal treatment may be formulated to meet specific objectives or well conditions. These and other materials, useful according to the invention, differ from traditionally used polymeric materials, such as polyacrylamide, xanthan, guars, cellulosic, and the like, since they substantially effect the surface energy differential between the formation and targeted fluids. 
     Not to be limited by any particular surfactant, particularly well suited for use as the treating surfactant for oil formations are those having the alkyl-group-containing amine oxide surfactants of the formula R 1 -R 2 -R 3  amine oxide, wherein R 1  is an alkyl group containing from 6 to 16 carbon atoms, more particularly from 8 to 14 carbon atoms, and may be linear, branched, saturated or unsaturated, and R 2  and R 3  methyl or ethyl groups. 
     Specific non-limiting examples of suitable surfactants include octyl-dimethyl amine oxide, nonyl-dimethyl amine oxide, decyl-dimethyl amine oxide, undecyl-dimethyl amine oxide, dodecyl-dimethyl amine oxide, tetradecyl-dimethyl amine oxide, hexadecyl-dimethyl amine oxide, coco-dimethyl amine oxide, lauryl-dimethyl amine oxide, cetyl-dimethyl amine oxide, palmitic-dimethyl amine oxide, stearic-dimethyl amine oxide, mysristic-dimethyl amine oxide, palmitoleic-dimethyl amine oxide, linoleic-dimathyl amine oxide, and linolenic-dimethyl amine oxide. 
     As an example, both laboratory testing and field results have shown that decyl dimethyl amine oxide surfactant can provide wetting properties that lead to lower capillary pressures. The contact angle resulting from the use of decyl dimethyl amine oxide surfactant has been shown to be higher than those for other conventional surfactants including ethoxylated linear alcohols with 10 to 12 carbon chain lengths, ethoxylated sulfate alcohols with 6 to 10 carbon chain lengths, fatty acid alcohol ether sulfates and betaines. Decyl dimethyl amine oxide surfactant has been shown to impact both sandstone and limestone formations. 
     The treating surfactant is added to a carrier fluid. The carrier fluid may be an aqueous fluid or non-aqueous fluid. The aqueous carrier fluid may be fresh water, salt water or a brine. Non-aqueous carrier fluids may include crude oil, mineral oil, diesel, polymerized glycols and mutual solvents such as ethyleneglycol monobutylether. The surfactant may be added to the carrier fluid in a batch operation or pumped into the treating line on the fly in an amount sufficient to accomplish the required alteration of the rock wettability; that amount being from about 2 or more times the critical micelle concentration (CMC) of the surfactant for the carrier fluid. In certain instances the surfactant may be added in an amount of from about 5 to about 50 times the CMC of the surfactant for the carrier fluid The surfactant may be at a concentration that is less than the solubility limit within the carrier fluid at the temperature the treatment fluid is designed for use. The surfactant is preferably dissolved in the carrier fluid and applied at a concentration less than the solubility limit at the temperature of application but greater than the CMC. However dispersions of the surfactant in the carrier fluid may also be effective. 
     The surfactant may be used to reduce or eliminate three-dimensional water coning, cusping or channeling through unfractured matrix with crossflow. 
     The surfactant may be used as a remedial treatment, as well as a prophylactic treatment. These treatments may be repeated if necessary. In remedial treatments, the surfactant treating fluid is injected into the watered-out zone, as is shown in  FIG. 5 . The volume of treatment fluid is dictated by both practical and theoretical limits. Preferably, a volume of surfactant sufficient to alter the wettability of the rock subject to the coning phenomena is needed. More preferably, additional volumes are used to expand the treated radius beyond the existing cone and deeper into the aquifer. The practical volume may be less due to economic considerations and the persistence of the treatment. Because the watered-out zone possesses a very high water saturation, it has a high relative permeability to aqueous systems. The surfactant, which may be carried in an aqueous carrier fluid, will therefore preferentially enter the areas in the most need of treatment. 
     In certain applications, the wellbore or a secondary wellbore may penetrate the aquifer or aqueous-fluid-bearing portion or zone of the formation. These wellbores may be perforated in the aqueous zone so that water may be produced through the wellbore prior to treatment to facilitate further mitigation of water production. This may also form an oil or hydrocarbon cone that extends downward into the water-bearing zone. In certain embodiments, water may be intermittingly or periodically produced from the well to facilitate formation of an oil or hydrocarbon cone that extends downward into the water-bearing zone. 
     After injection of the treatment fluid, the well may be shut in to allow oil or natural gas to displace the treating fluid into the aquifer and/or transition zone. Any suitable shut-in time may be used. In some embodiments, shut-in times may vary from about 12 hours, about 24 hours, about 48 hours, to about 1 week, about 2 weeks, or more. This allows oil or natural gas to downcone or further downcone into the aqueous zone below the area of perforations to create a blockage to prevent or reduce the production of water, as shown in  FIG. 6 . 
     Optionally, a suitable overflush fluid, which may be aqueous or non-aqueous, such as a hydrocarbon, such as oil (e.g. crude oil, mineral oil, etc.), alcohols such as methanol or ethanol or gas, depending upon the fluid produced, may be injected subsequently to the surfactant treatment fluid. This may alter both the oil zone and aquifer and effectively eliminates the capillary pressure since the hydrocarbon drives the local water/oil interface down toward the aquifer. The overflush fluid may contain substantially no oil-wetting or water-repelling surfactant. The overflush fluid may be a fluid in which the surfactant is soluble. The overflush fluid may be selected from those that will not substantially alter the wettability from neutral wetting to strongly oil wetting. The overflush fluid may also be one in which the surfactant is readily dispersible. Preferably the overflush fluid should have properties that will result in an efficient displacement of the treating fluid. 
     A preflush is optionally used to condition the reservoir rock for optimal absorption of the surfactant. Mutual solvents have the ability to remove deposits from the rock surface. Oxidizers, specific acids and acidic gases may be of benefit in conditioning the rock. Also, clay stabilizers may be employed in the preflush to prevent fines migration and swelling of water sensitive clays. 
     In a prophylactic treatment, the aquifer or water-bearing zone is penetrated. Perforations may be formed in the wellbore in the water-bearing zone. Water may be removed, as described previously, and the surfactant treatment fluid is injected into the water zone prior to further completing the well. This too may be followed by the injection of an overflush fluid to further displace the water of the water-bearing zone, as previously described. Any perforations of the wellbore in the water-bearing zone are isolated and then the wellbore may be perforated in the hydrocarbon zone to bring the well on production. 
     Subsequent to the injection of the surfactant treatment fluid or the hydrocarbon, if a hydrocarbon treatment follows, a further blocking agent may be introduced into the formation. Blocking agents may be those that are typically used in the mitigation of water production, and which are known to those skilled in the art. The blocking agents may be those gels or hydratable polymers that are crosslinked in situ or can include a polymer with relative permeability modifying (RPM) properties. Such blocking agents include hydratable polymers including polyacrylamides and modified polyacrylamides containing various monomers such as acrylic acid, methacrylic acid, vinyl pyrrolidone or sodium AMPS that are used alone as RPM or crosslinked in situ to form strong blocking gels, natural polymers such as xanthan gum, guar gum, derivatized guar gums, water soluble cellulose such as hydroxyethyl cellulose or carboxymethyl cellulose and the like. Typical crosslinkers include metallic crosslinkers such as chromium, zirconium, aluminum or cobalt, organic crosslinkers such as aldehydes, polyethyleneimines, phenolic-aldehydes, difunctional aldehydes such as glyoxal and glutaraldehyde. Other blocking agents include inorganic materials such as sodium silicate gels, aluminum gels, plastics including phenolplasts and epoxies, gels prepared from lignosulfonates, precipitation agents such as calcium silicates, hardenable resins and polyurethanes. 
     The above-described treatments may be conducted periodically. Thus, for example, the various treatments may be carried out at intervals of one month, two months, three months, six months, one year, two years, etc. This may be done on a predetermined schedule or in response to the concentration of surfactant that is found in the produced fluids. In such instances, the minimum effective surfactant concentration may be determined and monitored. When the surfactant concentration, as determined from the produced fluids, falls below an effective level, a subsequent treatment may be carried out. 
     In certain applications, treatment with the surfactant treating fluid may be carried out after first acidizing the oil zone, producing back the acid treatment after a suitable reaction time, and then treating with the surfactant to mitigate water production. 
     The treatment may also be used in fracturing operations. In such instances, the surfactant treatment fluid may be introduced in the formation as a prepad prior to conventional hydraulic fracturing. 
     If removal of the surfactant is necessary, the placed surfactant may be allowed to naturally desorb from surfaces over time. If more immediate removal is necessary, compounds that will interact with the surfactant may be introduced into the formation. These may include other surfactants, solvents, salt solutions, acids or bases, etc. that alter the association of the surfactant with the formation. 
     The surfactant treatment carried out in accordance with the invention has application to oil, gas and water wells. The surfactant treatment is very simple to carry out and may be injected into the well without the need for selective placement. This avoids the higher cost and logistical complexities associated with other interventional techniques. 
     The treatment may cause only a minimal reduction in rate from the productive interval. In contrast to conventional blocking materials, the surfactant treatment lends itself to removal or re-treatment. 
     The surfactant treatment can be applied in formations with fissures or fractures. The capillary pressure between two fracture faces can be quite large, especially if the fracture width is small. Such fractured formations thus may lend themselves to treatment by the surfactant fluid. 
     The following examples serve to further illustrate the invention. 
     EXAMPLES 
     Example 1 
     Various surfactants were tested using an apparatus such as that shown in  FIG. 1 . The capillary tubes were 0.8mm in diameter. The container and capillary tubes were each soaked in a hot nitric acid solution for 5 minutes, rinsed with deionized water and dried. Deionized water was added to the reservoir to form a baseline. The capillary tube was lowered into the reservoir, ensuring that no air was trapped in the tube while venting air through tube  22 . The rise of the fluid above the reservoir was measured with a ruler. The valve was turned by 180° and the equilibrium disturbed by injecting or removing some air with the piston. The capillary rise height was then reconfirmed. This procedure was repeated four times and a total of five readings were averaged and reported. The surfactant solution to be tested was added to the solution reservoir at the desired concentration and stirred to obtain a uniform concentration. The above procedure was repeated and the average of three readings was recorded. Next, three pore volumes of deionized water were flushed through the capillary to determine the persistence of the surfactant&#39;s ability to alter wettability. The capillary rise height was again measured. The capillary apparatus was then rinsed and cleaned with the nitric acid solution prior to measurements with a new surfactant solution. Another experiment was performed with two promising surfactants where the tube was shut-in over the weekend and the capillary heights measured again three days later. The results are presented in Table 1 below. 
     
       
         
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 1 
               
               
                   
               
               
                   
                   
                   
                   
                 % 
                   
                 % 
               
               
                   
                   
                 Product 
                 Initial 
                 Change 
                 Final 
                 Change 
               
               
                 Capillary 
                 Surfactant Dissolved 
                 Conc., 
                 Capillary 
                 vs. DI 
                 Capillary 
                 vs. DI 
               
               
                 Sample 
                 in DI Water 
                 vol % 
                 Rise, cm 
                 Water 
                 Rise, cm* 
                 Water 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 1 
                 DI water 
                 0 
                 3.56 
                 100 
                 3.56 
                 100 
               
               
                 2 
                 Lauryl-dimethyl amine oxide 
                 0.5 
                 0.940 
                 −74 
                 2.39 
                 −33 
               
               
                 3 
                 Cetyl-dimethyl amine oxide 
                 0.5 
                 1.04 
                 −71 
                 2.31 
                 −35 
               
               
                 4 
                 Mixture of coco trimethyl 
                   
                 1.09 
                 −69 
                 2.54 
                 −29 
               
               
                   
                 ammonium chloride and bis (2- 
               
               
                   
                 hydroxyethyl) cocoamine oxide 
               
               
                 5 
                 Decyl-dimethyl amine oxide 
                 5 
                 1.30 
                 −64 
                 1.40 
                 −61 
               
               
                 6 
                 Amphoteric alkyl amine 
                 1 
                 1.55 
                 −56 
                 2.44 
                 −32 
               
               
                 7 
                 Mixture of Dicoco Dimethyl 
                 1 
                 1.35 
                 −62 
                 1.35 
                 −62 
               
               
                   
                 Ammonium Chloride and Di- 
               
               
                   
                 Secondary Butyl Phenol w/10 
               
               
                   
                 Moles Ethylene Oxide 
               
               
                   
               
               
                 *After 3 pore volumes of flush with DI water. One pore volume is the volume held by the capillary. 
               
             
          
         
       
     
     Example 2 
     Samples 1, 5 and 7 from Example 1 were further aged for approximately 72 hours and retested. The results are presented in Table 2 below. 
     
       
         
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 2 
               
               
                   
               
               
                   
                   
                   
                   
                 % 
                   
                 % 
               
               
                   
                   
                 Product 
                 Initial 
                 Change 
                 Final 
                 Change 
               
               
                 Capillary 
                 Surfactant Dissolved 
                 Conc., 
                 Capillary 
                 vs. DI 
                 Capillary 
                 vs. DI 
               
               
                 Sample 
                 in DI Water 
                 vol % 
                 Rise, cm 
                 Water 
                 Rise, cm* 
                 Water 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 1 
                 DI water 
                 0 
                 3.56 
                 100 
                 3.56 
                 100 
               
               
                 5 
                 Decyl- 
                 5 
                 0.711 
                 −80 
                 0.711 
                 −80 
               
               
                   
                 dimethyl 
               
               
                   
                 amine oxide 
               
               
                 7 
                 Mixture of Dicoco Dimethyl 
                 1 
                 0.991 
                 −72 
                 1.30 
                 −64 
               
               
                   
                 Ammonium Chloride and Di- 
               
               
                   
                 Secondary Butyl Phenol w/10 
               
               
                   
                 Moles Ethylene Oxide 
               
               
                   
               
               
                 *After 3 pore volumes of flush with DI water. One pore volume is the volume held by the capillary. 
               
             
          
         
       
     
     While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes and modifications without departing from the scope of the invention. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.