RU2682833C2 - Method of re-fracturing using borated galactomannan gum - Google Patents

Abstract

FIELD: chemistry.SUBSTANCE: invention relates to re-fracturing of a subterranean formation. Method of re-fracturing a subterranean formation penetrated by a well having a number of zones, includes: a) hydraulic fracturing of the productive zone inside the subterranean formation, b) isolating the productive zone subjected to hydraulic fracturing from the second zone in the well by pumping to the well non-hydrated borated galactomannan gum and a cross-linking agent, where before transition to the cross-linked state, the non-hydrated borated galactomannan gum contains borate ions, and forming a thickened temporary seal by reacting said gum and cross-linking agent, thereby isolating said production zone from the second zone, c) breaking down said thickened temporary seal by injecting into the well a viscosity reducing agent, and reducing the viscosity of the thickened temporary seal by means of said agent pumped into well under pressure which is insufficient for the creation or expansion of fractures in the subterranean formation, and d) re-fracturing of said isolated zone after decomposition of the thickened temporary seal by pumping into the well a fluid for hydraulic fracturing of the formation under pressure, sufficient for the creation or expansion of fractures in the isolated productive zone subjected to hydraulic fracturing. Method of hydraulic fracturing a subterranean formation includes: a) pumping to the well non-hydrated borated galactomannan gum and a cross-linking agent, b) sealing the productive zone subjected to hydraulic fracturing relative to the other zone in the well by means of gel for temporary isolation due to the reaction of said gum and cross-linking agent to form temporary isolation gel from the product of said reaction, c) pumping into the well a viscosity reducing agent, reducing the viscosity of the gel for temporary isolation, removing the seal of said productive zone relative to another zone and removing the gel for temporary isolation from the well, where said agent is pumped into the well under pressure which is insufficient for the creation or expansion of fractures in the subterranean formation, d) re-fracturing the unsealed productive zone, subjecting it to hydraulic fracturing by pumping into said zone a fluid for hydraulic fracturing of a formation under pressure sufficient for the creation or expansion of fractures, e) pumping said gum and cross-linking agent into the well and forming a gel for temporary isolation between the zone subjected to re-fracturing, and another zone by reacting said gum and cross-linking agent. Method for increasing productivity of oil-and-gas bearing formation penetrated by a well, having a number of productive zones, includes a) forming a gel for temporary isolation between a zone previously subjected to hydraulic fracturing and another zone by pumping said gum and delayed-action crosslinking agent and reaction thereof, b) pumping a viscosity reducing agent into the well, reducing the viscosity of the gel for temporary isolation and then removing it from the well, c) pumping into the well a fluid for hydraulic fracturing of the formation under pressure sufficient to create or expand the fracture in the subterranean formation, and re-fracturing the productive zone, d) injecting into well a well treatment fluid containing said gum and delayed-action crosslinking agent, and e) isolating said production zone by curing the well treatment fluid containing said gum and delayed-action crosslinking agent. Invention is developed in dependent items of the formula.EFFECT: technical result is higher efficiency of re-fracturing treatment.20 cl, 7 dwg, 2 tbl, 9 ex

Description

FIELD OF THE INVENTION

The present invention relates to the use of a fluid (hereinafter referred to as a fluid) for treating wells and containing boron galactomannan gum as a temporary compaction material for the purpose of providing zonal isolation between the intervals of the wellbore, and also as an alternative to cement. The invention also relates to a method for repeated hydraulic fracturing of an underground formation, in which the temporary compaction material is removed from the well by exposing it to a viscosity reducing agent.

State of the art

The subterranean formation in which the well passes usually contains a number of clearly distinguishable promising zones or formations. In the process of extracting fluids from the well, it is desirable, as a rule, to create a connection only with promising zones or formations so that the stimulating treatment does not accidentally affect an unproductive zone or a zone of less interest. Selective stimulation (through, for example, hydraulic fracturing and acid treatment) becomes predominant as well life is shortened and its productivity decreases.

Selective stimulation is usually carried out by means of one or more shooting perforators, the perforator being moved on a cable or pipe into the well and placed next to the prospective zone and / or formation, after which they selectively perforate to perforate this zone and / or formation. Then the puncher is again moved on the cable to another promising zone or formation and the latter is selectively perforated. This procedure is repeated until the perforation of all promising zones and / or formations is completed, the field of which returns the firing punch to the surface with a cable. If it is necessary to perform hydraulic fracturing (hydraulic fracturing), hydraulic fracturing fluid is pumped into the well at a pressure higher than the hydraulic fracturing pressure of a given zone and / or formation. To prevent the flow of hydraulic fluid for hydraulic fracturing into areas with greater porosity and / or lower pressure, a mechanical device, such as a twin packer, cork or sand pad, is first installed in the well between the zone that has just been fractured and the zone to be fractured to isolate stimulated zone from further contact with hydraulic fracturing fluid. This procedure is repeated until the perforation and hydraulic fracturing in all promising areas.

After completion of completion operations, it is necessary to drill or otherwise remove each plug from the well to allow the produced fluid to surface through the well. Hoisting operations in the well for perforation and stimulation of each of several zones and the use of such plugs to isolate previously treated zones and / or formations from further contact with the processing fluid are associated with significant time and cost.

A number of publications report on various methods and devices for implementing zonal isolation between intervals of a well that are not related to moving perforating equipment into and out of the well during completion work in various promising areas. However, such methods and devices provide selective isolation of target production intervals in the well from non-productive intervals.

A number of later publications report that zonal isolation is provided using isolating devices that allow selective processing of productive (or previously productive previously) intervals in multi-well wells. For example, US Pat. No. 6,386,288 describes a mechanical zonal isolation system that can be located on the outside of the casing (cemented to the wellbore), which allows completion work in any interval and its stimulation and / or processing independently of others intervals. In this way, stimulation and / or processing of selected intervals of the subterranean formation can be performed. In such devices, flap valves located between firing perforators can be used.

Further, US Pat. No. 7,576,062 describes an insulating device comprising filter couplings and a series of swellable packers placed around the liner, as well as a displaceable tool inside the liner designed to open holes to control fluid flows from the well.

Zone isolation devices are expensive. Being fixed in the required place with cement mortar, they can be removed from the well only by their damage or destruction. Therefore, alternative methods are needed that would hold the casing in the desired location of the well.

In addition, a search was conducted for alternative options for attaching the casing to the wellbore. Cement mortar is traditionally used to attach pipes and casing to the wellbore. The cement slurry is usually injected into the pipe or casing and supports the outside of the pipe or casing throughout the annular space between the outside of the casing and the wellbore. The cement mortar is then allowed to solidify and harden to hold the casing in place. The use of conventional cement mortars in the case of devices for zonal isolation is undesirable, since the removal from the well of these devices will necessarily be associated with their damage or destruction.

A search was also conducted for alternatives for methods of re-fracturing a selectively stimulated formation containing a number of clearly distinguishable productive zones. Repeated hydraulic fracturing (PGR) is often required in case of unsatisfactory performance of this operation in any productive zone of the well. The consequence of this is usually unsatisfactory production results from this productive zone. Even with satisfactory hydraulic fracturing, production from this productive zone may no longer reach the required level. Over a long period of time, production from a horizontal well in which hydraulic fracturing was previously carried out may fall below the minimum threshold level. One of the methods to increase hydrocarbon production is to create new fractures in the underground reservoir.

Disclosure of invention

Proposed in the present invention, the fluid (fluid) for well treatment provides isolation during completion of the well and can be removed after or during the inflow from the well. The removal of the fluid for treatment of wells proposed in the present invention, after the start of production as a result of hydraulic fracturing, can therefore be performed practically without damaging the surface of the formation at the bottom of the well.

The well treatment fluid contains borated galactomannan gum, a crosslinking agent and, preferably, a destructor (gel thinner). Prior to curing with a cross-linking agent, borated polygalactomannan contains borate ions. Boronated polygalactomannan can be pumped into a well bore in the formation that is not hydrated in the form of powder or hydrocarbon slurry.

Galactomannan is preferably guar gum and its derivatives, for example derivatives of carboxymethyl ether and hydroxyalkyl ether. In addition, non-derivatized guar may also be preferred.

The hydration of the well treatment fluid can be controlled by changing the pH and / or crosslinking agent, for example, a heat activated crosslinking agent of a delayed action. So, the hydration of the fluid for processing the wells can be delayed until the fluid reaches the desired location in the well. Therefore, the well treatment fluid can be efficiently placed for the preferred hermetic compaction, or blocking, of productive zones in the formation, since the hydration delay of this fluid can be adjusted up to several hours.

These fluids are particularly useful for treating formations that include a number of productive zones. The treated well usually contains a zone isolation system in the prospective zone. Processing fluid can be used in vertical and non-vertical wells. In such cases, perforation and hydraulic fracturing can be performed in the well without using cement.

Thus, in one embodiment of the present invention, there is provided a method for increasing the productivity of a formation in which a well passes, comprising injecting unhydrated borated galactomannan gum and a crosslinking agent into the well. Before transitioning to a crosslinked or cured state, non-hydrated borated galactomannan gum contains borate ions.

In another embodiment, the present invention provides a method for increasing the productivity of an oil and gas reservoir in which a well passes and which contains a number of productive zones. In this method, the unhydrated borated galactomannan gum and a crosslinking agent are supplied to a region near a predetermined productive zone in the well, the borate ions being introduced into the unhydrated borated galactomannan gum before crosslinking. A predefined production zone is isolated from the remaining zones of the well by solidifying the fluid for treating the wells. Then carry out the perforation of a predetermined productive zone. After that, hydraulic fracturing is performed in a perforated predetermined productive zone, feeding into the last hydraulic fracturing fluid under a pressure sufficient to form cracks in this zone.

In another embodiment, the present invention provides a method for increasing the productivity of an oil and gas reservoir in which a cemented vertical well is constructed comprising a casing and a number of productive zones. In this embodiment, perforation of the well production zone is performed. Then, the perforated productive zone is subjected to hydraulic fracturing by introducing hydraulic fluid for hydraulic fracturing under a pressure sufficient to form cracks in this zone. After that, the fluid intended for well treatment and containing boron galactomannan gum and a crosslinking agent is supplied to the casing above the perforated productive zone subjected to hydraulic fracturing, and boron galactomannan gum containing borate ions introduced prior to crosslinking. Then, the treatment fluid is cured.

In another embodiment, the present invention provides a method for increasing the productivity of an oil and gas underground formation. In this method, a well treatment fluid containing unhydrated borated guar and a crosslinking agent is fed into the annular space between the wall of the wellbore and the pipe string located in the last column. The pipe string contains a device for zonal isolation. Non-hydrated boron guar contains borate ions introduced prior to crosslinking. Then, the treatment fluid solidifies and the productive zone is isolated within the formation. After that, the isolated productive zone is perforated inside the zone isolation device. Then, the isolated productive zone is subjected to hydraulic fracturing by introducing hydraulic fluid for hydraulic fracturing under a pressure sufficient to form cracks in this zone.

In another embodiment, the present invention provides a method for increasing the productivity of an oil and gas subterranean formation in which a non-vertical well passes. In this embodiment, a first packer is introduced into the well. A device for zonal isolation is placed in the well near the first packer. Then the second packer is introduced into the well until the area determined by the zone isolation device and limited by the first and second packers is obtained. After that, unhydrated borated guar and a crosslinking agent are fed into the well. Then curing of the non-hydrated borated guar takes place. Moreover, the area bounded by the first and second packers is hermetically isolated from other areas of the well. After that, the isolated zone is subjected to hydraulic fracturing, introducing into it the hydraulic fluid for hydraulic fracturing at a pressure sufficient to form cracks in this zone. These steps can be repeated in another area of the well.

In another embodiment, the present invention provides a method for re-fracturing a subterranean formation in which a well passes. In this method, a viscosity reducing agent is pumped into the well. In this case, the viscosity of the thickened (gelled) temporary compaction material decreases. The thickened temporary compaction material is the product of the interaction of unhydrated borated galactomannan gum and a crosslinking agent. The viscosity reducing agent is pumped into the well at a pressure not sufficient to create or expand a fracture in the subterranean formation. After that, hydraulic fracturing fluid is pumped into the well at a pressure sufficient to form or expand a fracture in a predetermined production zone of the well.

In another embodiment, the present invention provides a method for re-fracturing a subterranean formation in which a well extends, wherein a productive zone previously subjected to hydraulic fracturing is isolated from another zone of the well by means of a temporary isolation gel. Gel for temporary isolation is obtained from boron galactomannan gum. The viscosity reducing agent is pumped into the well at a pressure insufficient to create or expand a fracture in the subterranean formation. The viscosity of the gel for temporary isolation is reduced. After that, in the production zone previously subjected to hydraulic fracturing, hydraulic fracturing can be carried out by supplying hydraulic fracturing fluid to this zone under a pressure sufficient to create or expand a fracture. Then, a well treatment fluid containing unhydrated galactomannan gum is fed into the area above the productive zone subjected to the fracturing treatment. At the same time, the zone subjected to the hydraulic fracturing is isolated as a result of the curing of the fluid for treating the wells.

In another embodiment, the present invention provides a method for increasing the productivity of an oil and gas reservoir, in which a well containing a number of productive zones passes. In this method, a well treatment fluid containing a viscosity reducing agent is pumped into the productive zone inside the well previously subjected to hydraulic fracturing. The productive zone previously subjected to hydraulic fracturing is isolated from the second productive zone of the well by means of a temporary isolation gel obtained from boron galactomannan gum. After that, you can reduce the viscosity of the agent for temporary isolation and remove it from the well. Then, in the productive zone previously subjected to hydraulic fracturing, hydraulic fracturing can be carried out by injecting hydraulic fluid for hydraulic fracturing under pressure sufficient to create or expand a fracture. After that, fluid can be pumped into the well for processing, containing boron galactomannan gum. In this case, the productive zone subjected to PGRF can be isolated from another productive zone inside this well as a result of the curing of the fluid for treatment of wells containing boron galactomannan gum.

Brief Description of the Drawings

For a more complete understanding of the drawings referred to in the detailed description of the present invention, a brief description of each of these drawings is shown below, showing:

FIG. 1 - the use of processing fluid in a horizontal well containing a zone isolation system,

FIG. 2 - the effect of changes in pH at the onset of hydration of the gel,

FIG. 3 - the effect of the moderator on the onset of hydration of the gel,

FIG. 4 - the effect of changing pH values through a moderator on the onset of gel hydration,

FIG. 5 - the effect of changing pH values through a moderator on the onset of hydration of the gel,

FIG. 6 - the ability of the gel to maintain high viscosity at a low shear rate for isolation,

FIG. 7 is a diagram of the experiments described in the examples.

DETAILED DESCRIPTION OF THE INVENTION

The boron galactomannan gum used in the well treatment fluids mentioned herein is galactomannan gum containing borate ions introduced prior to crosslinking or curing. Such boron galactomannan gums are described in US Pat. No. 3,808,195, incorporated herein by reference. Boronated polygalactomannan can be obtained by introducing galactomannan into a material containing borate ion, i.e. material in which a borate ion can be released to react.

Non-hydrated boron galactomannan can be pumped in powder or suspension in water or in mineral oil added to the water. The amount of boron galactomannan injected into the formation is usually about 100-1000 pounds per thousand gallons of water (ppt from the English "part per thousand"), preferably about 250-750 ppt. When using a hydrocarbon suspension, the amount of boron galactomannan in the latter is approximately 3-5 pounds per gallon of hydrocarbon.

Preferred galactomannins for use in the invention are guar gum and its derivatives, including natural or non-derivatized guar, enzyme-treated guar gum (obtained by treating the natural guar gum with galactosidase, mannosizad or another enzyme), and derivatized guar. Polygalactomannan derivatives include water-soluble derivatives, such as carboxyalkyl ethers, for example carboxymethyl ether derivatives, hydroxyalkyl ether derivatives, such as hydroxyethyl ethers and hydroxypropyl ethers of polygalactomannan, carbamylethyl ethers of polygalactomannan, cationic polygalactomannanes.

Along with this, suitable derivatized guars are guars obtained by treating the natural guar gum with agents for introducing carboxyl groups, hydroxylalkyl groups, sulfate groups, phosphate groups, etc. Preferred are either hydroxylalkylated guar (such as hydroxypropyl guar, hydroxyethyl guar, hydroxybutyl guar) or modified hydroxyalkylated guars like carboxylated guars, such as carboxyalkylated guars like carboxymethyl guar and hydroxycarboxylated, such as hydroxycarboxylic, ), including guars having a molecular weight of about 1 to 3 million. The carboxyl content of such guar derivatives can be expressed as a degree of substitution and a range of about 0.08-0.18, and the hydroxypropyl content can be expressed as a molar substitution (defined as the number of moles of hydroxyalkyl groups per mole of anhydroglucose) and a range of about 0.2-0.6.

Boron galactomannan is usually obtained by soaking polygalactomannan in an alkaline aqueous solution of a material containing borate ions, which ensures the absorption of the whole solution by polygalactomannan, and then grinding and drying polygalactomannan. The amount of water in an alkaline aqueous solution is approximately equal to the amount of polygalactomannan. The alkalinity of the solution is achieved by using hydroxide of an alkali or alkaline earth metal. The concentration of alkali or alkaline earth metal hydroxide in the solution is about 0.3-0.5% by weight relative to the weight of polygalactomannan. After the solution is absorbed by polygalactomannan, the latter is ground and dried at a temperature typically of about 150-250 ° C, to about the initial moisture level in untreated polygalactomannan, which typically contains about 9-12% water by weight. Other processes for producing borated polygalactomannan and its derivatives are described in US Pat. No. 3,808,195.

Materials containing a borate ion preferably include salts of alkali metals, alkaline earth metals and ammonium with borate anions. Borate anions include tetraborate, metaborate and perborate anions. If we take the molecular weight of the galactomannan unit equal to 200, then the molar ratio of substituent groups in the reaction mixtures will be from 0.1 to 3, which gives a molar substitution value of at least 0.1. Molar substitution is the average number of substitution radicals per mole of the anhydrohexose unit of the polygalactomannan resin. The concentration of borate ions corresponds to the composition of borax Na ₂ B ₄ O ₇ ⋅ 10H ₂ O.

The borated guars resulting from the reaction of the borate ion and polygalactomannan gum are dispersed in water, showing a limited ability to crosslink when hydrated polygalactomannan and alkaline pH of the resulting sol. The dispersion of polygalactomannan in water usually occurs at the same pH value as in the case of the untreated polymer. Since the hydration rate of borated polygalactomannan is greatest at an almost neutral or acidic pH, the borated polygalactomannan does not hydrate at higher pH. Due to the fact that the fluid for treatment of wells is not more than partially hydrated in the reservoir, it has a low viscosity, which minimizes the friction pressure and allows the flow of this fluid to be pumped at a low injection rate or using flexible tubing.

The viscosity of the well treatment fluid can be adjusted and maintained at the desired temperature by controlling hydration by changing pH values and providing subsequent crosslinking of the borated polygalactomannan (preferably by adding a crosslinking agent). Suitable pH adjusting agents that can be used to maintain the desired pH include soda ash, potassium hydroxide, sodium hydroxide and carbonates and bicarbonates of alkali and alkaline earth metals. The typical pH required to cure the fluid for treatment of wells exceeds 8.0, more preferably more than 9.0.

Therefore, the well treatment fluid is highly effective at selective compaction, or blocking, of productive zones in the formation, since the hydration of this fluid can be controlled with a delay of up to several hours using a certain amount of borate used in the guar or guar derivative, as well as the pH of the system. For example, the viscosity of this fluid can usually be reduced by pH or temperature controlled destructors when passive zone isolation is no longer required. Bringing the pH value to the level corresponding to a strongly alkaline medium, one can delay the crosslinking of boronated polygalactomannan even further up to high temperatures, for example, up to 120 ° F and often up to 350 ° F.

Thus, the crosslinking agent used in the fluid of the present invention is a conventional delayed crosslinking agent (delaying the hydration of polygalactomannan), although other crosslinking agents may be used. In many cases, hydration can be controlled within 24-36 hours before the formation of a gel with sufficient viscosity, functioning as a sealant.

Borax is used as a crosslinking agent, especially at high temperatures. In addition to borax, other compounds that release the borate ion can be used, as well as organometallic or organic metal ion complex compounds, including at least one transition or alkaline earth metal ion, as well as mixtures thereof.

Suitable borate ion releasing compounds include, for example, any boron compound releasing borate ions in the composition, for example boric acid, alkali metal borates such as sodium diborate, potassium tetraborate, sodium tetraborate (borax), pentaborates, etc. ., as well as alkaline borate systems and zinc borates. Such borate ion releasing compounds are described in US Pat. Nos. 3,058,909 and 3,974,077, incorporated herein by reference. In addition, such borate-releasing compounds include boron oxide (for example, selected from H ₃ BO ₃ and B ₂ O ₃ ) and polymeric borate compounds. An example of a suitable polymeric borate compound is a polymeric compound of boric acid and an alkaline borate system sold by Borax (Valencia, California, USA) under the trademark Polybor®. Mixtures of any of the borate ion releasing compounds mentioned may also be used. In order for crosslinking to occur, the pH value of such borate-releasing compounds should typically be in an alkaline environment (e.g., 8.0-12).

In addition, preferred crosslinking agents are organometallic compounds and organic metal-bonded organic complexes that can give zirconium IV ions, for example zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium diisopropylamine can also titanium IV ions, for example, such as titanium ammonium lactate, triethanolamine titanium and titanium acetylacetonate. Zr (IV) and Ti (IV) as ions or hydroxy ions can also be directly added to the composition.

Such crosslinking agents in the form of organometallic compounds and organic complex compounds with a mediated metal bond containing titanium or zirconium in a valence state of +4 described in GB 2108122, incorporated herein by reference, are obtained by the reaction between zirconium tetraalkoxides and alkanolamines at substantially anhydrous conditions. Other zirconium and titanium crosslinking agents are described, for example, in US Pat. Nos. 3,888,312, 3,301,723, 4,460,751, 4,477,360, European Patent 92,755 and US 4,780,223, each of which is incorporated herein by reference. Organometallic compounds and organic complex compounds with a mediated metal bond, such as crosslinking agents containing titanium and zirconium in a valence state of +4 (oxidation), may contain one or more alkanolamine ligands, such as ethanolamine (mono-, di- or triethanolamine) ligands for example, such as bis (triethanolamine) bis (isopropyl) titanium (IV). In addition, these compounds can be supplied as inorganic oxides such as zirconia or titanium dioxide. Such crosslinking agents are typically used at a pH also in the range of about 6-13.

Any suitable crosslinking metal ions, metal-containing molecules, or mixtures of such ions and molecules may also be used. In one of the preferred embodiments of the present invention, the crosslinking agent for use in the heat insulating composition of the present invention is a reagent capable of transferring Zn (II), calcium, magnesium, aluminum, Fe (II) and Fe (III) into this composition. These elements can be incorporated directly into the composition as ions or as compounds of multivalent metals, such as hydroxides or chlorides, from which ions can be released.

As mentioned above, crosslinking ions or molecules can be obtained by dissolving in a solution of compounds containing the corresponding metals or metal ion in pure form. The concentration of the crosslinking agent depends on factors such as polymer concentration and temperature in the annular space, and is usually in the range of about 5-2000 ppm, preferably about 100-900 ppm. An important advantage of the invention is that it enables the use of higher concentrations of crosslinking metal ions or metal-containing molecules, which provides improved crosslinking.

Well treatment fluids containing borated galactomannan gum are particularly useful in the case of treatment of formations for which there is information about the presence of several productive zones. For example, in some formations, such as shale formations, it may be necessary to perform multi-stage hydraulic fracturing, where the number of stages can be from 6 to 40. Well treatment fluid can function as an insulating system for a period of several hours to several days. The processing fluid can be used in vertical and non-vertical wells, but it can be most used in horizontal wells.

Well treatment fluid is particularly suitable as a passive chemical ring insulating system for isolating stimulated promising areas. The processing fluid may be fed into a well with a casing installed or into an open hole.

The well treatment fluid described herein is particularly useful in combination with a mechanical zone isolation system. In these methods, it is usually required to perform perforation and hydraulic fracturing in an isolated area without the use of cement.

In FIG. 1 shows a horizontal well 10 extending in a formation 12 comprising a conductive casing 15 and an intermediate casing 20 and equipped with a pipe 25 and a mechanical zone isolation system 30. The well treatment fluid 27 is fed into the well and fills the space between the pipe 25 and the casing 15. After the fluid has solidified, the string 20 is perforated and the formation 12 is subjected to hydraulic fracturing, resulting in fracturing 40. Upon completion of the hydraulic fracturing, the fluid viscosity sharply changes due to interaction with a destructor (destructive agent). After fluid is removed from the well, an intermediate string 20, a pipe 25, and a zonal isolation mechanical system 30 can also be removed.

In another embodiment of the present invention, perforation of a production zone of a well containing a series of production zones may first be performed. Then, fluid for hydraulic fracturing can be supplied to the perforated productive zone under a pressure sufficient to form cracks in this zone. The well treatment fluid described herein can be fed into a perforated production area subjected to hydraulic fracturing. After that, the perforated production zone can be isolated by curing the fluid for treatment of wells. If necessary, perforation of another productive zone of the well can be performed and the process can be repeated. This procedure is usually carried out by cementing the annular space of a vertical well before perforation of the first zone. In addition, one or more productive zones may comprise a zonal isolation system as described above.

In another embodiment of the present invention, a well treatment fluid may be supplied to a predetermined well production zone comprising a series of production zones. Then, the fluid in the predetermined production zone is cured to isolate this zone from other zones of the well. After this, a predetermined zone can be perforated and subjected to hydraulic fracturing, since this promising zone is hermetically isolated from other zones.

The processing fluid can also be used in a method that also uses a mechanical device, such as for example a packer, cork or sand pad. Such mechanical devices may first be installed in the well between the zone to be fractured and the adjacent zone of the well. This method is more appropriate to apply in non-vertical wells. A device for zone isolation can be installed in one or more zones subject to hydraulic fracturing, in the area bounded by two packers. Then, processing fluid may be supplied to the well. After curing the well treatment fluid, the area between the first and second packers is hermetically isolated from other zones in the well. In this isolated area, hydraulic fracturing can subsequently be performed. This process can then be repeated periodically to create cracks in other promising areas of the well. After the destruction of the gel forming the fluid for treating the well, all zone isolation systems can be removed from the well.

Along with providing effective zonal isolation following stimulation, well treatment fluid also minimizes cementing of natural fractures. When using conventional cements inside a well, situations often arise when cement enters natural fractures after drilling and / or perforating the formation. This leads to clogging of natural cracks. The proposed well treatment fluid can be used as an alternative to cement or as an addition to the latter.

In such cases, a fluid containing a suspension of boron galactomannan can be fed into the annular space between the wall of the wellbore and the pipe string located in the well. In a preferred embodiment of the present invention, a zone isolation device is arranged on a pipe string. Following the curing of the fluid, perforation of the isolated productive zone within the zone isolation device can be performed here. As a device for zone isolation, a multi-interval hydraulic fracturing device known in the art can be used, for example, the device described in US Pat. No. 6,386,288. The well can then be subjected to hydraulic fracturing at a pressure sufficient to form cracks in the isolated production zone. In such cases, the well may be non-vertical.

In one alternative embodiment of the present invention, the well comprises only a tubing string without a casing string. The mechanical insulating device is connected to the tubing string.

The passivity of the zonal isolation provided by the fluid is that the borated galactomannan can be removed from the well as a result of gel degradation. Due to this, the fluid can be used instead of a mechanical packer. Therefore, the methods of passive zonal isolation presented in the present description, provide annular isolation like conventional cements without damaging the formation. Thus, in the preferred mode of operation, the annular insulation system provided by the crosslinked gel is discharged from the well during subsequent work to obtain inflow from the well, while the surface of the reservoir remains virtually intact, which allows production to begin after hydraulic fracturing.

The well treatment fluids described herein are particularly effective in applications where PFG is highly desirable. A sealing system containing borated galactomannan gum can be degraded, and borated galactomannan gum can be removed from the well by applying a viscosity reducing agent to the latter. The viscosity reducing agent at least partially degrades the thickened borated galactomannan gum, as a result of which the latter becomes less viscous and can therefore be removed from the well. Thus, sealing systems that isolate, according to the foregoing, a fractured production zone from another formation zone by a borated galactomannan gum can be removed from the well so that a previously isolated production zone can be subjected to hydraulic fracturing again.

The fluid containing the viscosity reducing agent is pumped into the well at a pressure not sufficient to create or expand a fracture in the formation. Thus, after the destruction of the sealing system (and the preferred removal of the borated galactomannan gum from the well), hydraulic fracturing fluid can be pumped into the well at a pressure sufficient to create or expand a fracture in the formation. In this way, hydraulic fracturing can be carried out in the reservoir zone previously subjected to this operation.

As a rule, hydraulic fracturing in a formation is carried out by pumping hydraulic fluid for hydraulic fracturing into a predetermined production zone of a well in which hydraulic fracturing has previously been performed or an attempt has been made to conduct hydraulic fracturing and which contains a number of productive zones. So, for example, it is possible to carry out hydraulic fracturing in a certain region of the reservoir in a multi-zone well, hydraulically isolating the first region that has previously been fractured at least once from a portion of this multi-zone well located relative to this first region from the wellhead and performing hydraulic fracturing in this first area. After the completion of the hydraulic fracturing, the well treatment fluid containing unhydrated galactomannan gum can be fed into the well, as described above, and the zone subjected to the hydraulic fracturing can be isolated by curing the well treatment fluid.

It should be borne in mind that the method of performing hydraulic fracturing can include a series of hydraulic fracturing operations, during which a fluid containing a viscosity reducing agent is fed into the well, temporary consolidation material is removed to ensure blocking of the productive zone relative to another zone of the formation, hydraulic fracturing is performed, and fluid is fed into the well containing boron galactomannan gum, and cure it to isolate the productive zone subjected to PGRF from other productive zones of the formation, and then repeat the process.

Suitable viscosity reducing agents include any substance that is suitable for reducing the viscosity of a fluid containing boron galactomannan gum. Examples of suitable substances include, but are not limited to, oxidizing agents (such as sodium bromate), amines, acids, acid salts, acid-forming substances, enzyme breakers (enzyme breakdown agents), encapsulated breakdown agents, etc., as well as combinations thereof. The viscosity reducing agents provide for the destruction of the borated galactomannan gum in the well treatment fluid, whereby the degraded fluid can be removed from the subterranean formation to the surface.

Suitable acids include hydrochloric acid, formic acid and sulfamic acid, and acid salts include sodium bisulfate.

Suitable oxidizing agents include alkaline earth and other metal peroxides (such as magnesium peroxide, calcium peroxide and zinc peroxide), organic peroxides, bleach, persulfates (neat or encapsulated), for example, ammonium persulfate, sodium persulfate, ammonium peroxodisulfate and potassium persulfate, chromium salts, sodium bromate, sodium perchlorate, magnesium perborate, calcium perborate, etc.

Enzymatic destructors, such as galactomannases, capable of breaking the main chain of a crosslinked gel into fragments of a monosaccharide and a disaccharide can also be used.

An agent that reduces the viscosity is fed into the well in an amount sufficient to at least partially destroy the borated galactomannan gum and to remove the temporary compaction material used to isolate the productive zone previously subjected to hydraulic fracturing.

The following examples illustrate some embodiments of the present invention. Other embodiments encompassed by the claims will be apparent to those skilled in the art upon review of the description. It is understood that the present description, together with examples, is merely illustrative, and the scope and essence of the invention are determined by the attached claims.

Unless otherwise indicated, all percentages given in the examples relate to mass fractions.

Examples

The following materials are used in the examples below:

- polymer - boron guar supplied by Baker Hughes Incorporated under the name GW-26,

- borax, used as an additive that slows down hydration (and also acts as a crosslinking agent),

- GBW-25 destructor - sodium bromate supplied by Baker Hughes Incorporated.

Viscosity was measured with a high pressure and high temperature viscometer (Model 5550 manufactured by Chandler).

Example 1. The effect of changes in pH at the beginning of hydration of the gel was investigated by measuring viscosity. The results are shown in FIG. 2. For each experiment, a gel was prepared using 100 ppt of polymer in water. The pH value for this suspension was 8.84. Using a solution of sodium hydroxide (10% by weight in water), the pH was increased to 9.5, 9.75 and 10.1. This suspension was loaded into a viscometer and viscosity was measured at a shear rate of 100 sec ^-1 . The temperature of the viscometer was raised from 70 to 250 ° F for two hours and then kept constant at 250 ° F for another hour. From FIG. 2 shows that pH affects the viscosity as follows:

a) at a pH above 9.75 the gel does not hydrate and does not acquire viscosity at all;

b) at a pH of 9.5, the gel viscosity begins to increase after 60-65 minutes, but this growth is short-term;

c) at a pH of 8.84, the viscosity of the gel begins to increase after 30 minutes, similar to its behavior at room temperature in tap water. From FIG. 2, in addition, it follows that the pH can be used to control the time of onset of hydration.

Example 2. Using the above procedure, the effect of adding borax as a moderator at a pH value of 9.5 was investigated. The results are shown in FIG. 3. For each experiment, a gel was prepared using 100 ppt of polymer in water and a sodium hydroxide solution to adjust the pH. Borax was added as a retarding agent in a percentage concentration by weight of 1, 2 and 3% by weight of the polymer. The suspension was loaded into a viscometer and viscosity was measured at a shear rate of 100 sec ^-1 . The temperature of the viscometer was raised from 70 to 250 ° F for two hours and then kept constant at 250 ° F for another hour. The results show that borax alone (without any pH adjustment) has little effect on hydration retention, but when combined with an increase in pH from 8.84 to 9.5, it provides a significant difference in slowing down the hydration rate. More specific:

a) a control experiment with a gel at a natural pH value of 8.84 and a percentage concentration of borax by weight, amounting to 2% by weight of the polymer, showed a slight difference in hydration;

b) for a gel with a pH value adjusted to 9.5, at a percentage concentration of borax by weight of 1% by weight of the polymer, a hydration delay of about 80 minutes was recorded;

c) in a gel with a pH value adjusted to 9.5, at a percentage concentration of borax by weight of 2% by weight of the polymer, a hydration delay of about 120 minutes was recorded;

d) for a gel with a pH value adjusted to 9.5, with a percentage concentration of borax by weight of 3% by weight of the polymer, a delay in the onset of hydration was recorded by approximately 100 minutes, and complete hydration was delayed by 140 minutes.

For greater illustrative purposes, the pH of the gel was adjusted to 9.5 in accordance with Example 1, which is also reflected in FIG. 3. It is clear that the addition of a moderator along with an increase in pH to 9.5 allows better control of the time of onset of hydration.

Example 3. A study was made of the effect of pH and moderator on the hydration time, the results of which are shown in FIG. 4. For each experiment, a gel was prepared using 100 ppt of polymer in water. The pH value for this suspension was 8.84. Lower pH values (8.5 and 8.75) were obtained by adding acetic acid. Higher pH values (9 and 9.2) were obtained by adding sodium hydroxide solution (10% by weight in water). The suspension was loaded into a viscometer and viscosity was measured at a shear rate of 100 sec ^-1 . The temperature of the viscometer was raised from 70 to 100 ° F for 30 minutes and then kept constant at 100 ° F for another 90 minutes. In some experiments, borax was added as a moderator. The results show that hydration time can be changed by changing the pH. More specific:

a) a gel with a natural pH value of 8.84 and a percentage concentration of borax by weight, amounting to 3% by weight of the polymer, showed a slight difference in hydration;

b) for a gel without a moderator and with a pH value adjusted to 9.2, and a gel with a pH value of 8.75 and a moderator concentration of 1%, no significant hydration was detected;

c) the hydration delay was recorded in a gel without a moderator and with a pH value adjusted to 9.0, in a gel without a moderator and with a pH value adjusted to 8.75, and in a gel with a moderator concentration of 1%, and with a value The pH was adjusted to 8.5, but the time for the appearance of hydration signs (when the viscosity begins to increase and reaches a certain limit value of at least 1000 cP) varied from 25 to 52 minutes.

Example 4. Using the above procedure, the combined effect of pH and moderator on the hydration time was investigated. For each experiment, a gel was prepared using 100 ppt polymer in water. The pH value for this suspension was 8.84. Using a solution of sodium hydroxide (10% by weight in water), the pH was increased to 9 and 9.25. This suspension was loaded into a viscometer and viscosity was measured at a shear rate of 100 sec ^-1 . The temperature of the viscometer was raised from 70 to 150 ° F for 30 minutes and then kept constant at 150 ° F for another 90 minutes. The results show that hydration time can be changed by changing both the concentration of the moderator and the pH value. In particular, the onset of hydration ranged from 35 to 90 minutes, which is longer than in example 3.

Example 5. Using the above procedure was also investigated the optimal result obtained in the above examples (3% borax and pH 9.65), in order to establish the possibility of achieving high viscosity for insulation. The results are shown in FIG. 6. For this experiment, a gel was prepared using 500 ppt of polymer in water, a 10% sodium hydroxide solution to adjust pH and borax as a moderator. This suspension was loaded into a viscometer and viscosity was measured at a shear rate of 100 sec ^-1 . The temperature of the viscometer was raised from 70 to 250 ° F for two hours and then kept constant at 250 ° F for another 6 hours. After an initial two-hour temperature increase in this study, the constant shift was reduced from 100 sec ^-1 to 0.1 sec ^-1 (in order to simulate the static conditions of the blocking gel after it was placed). This study shows that with a small shift, the viscosity reaches a value in excess of a million cP.

Example 6. The ability to pump the gel when placed in a horizontal position and hold it there during a pressure drop was determined by using two high-pressure cells to determine fluid leakage (about eight inches long and two inches in diameter), one of which was horizontal and the other vertically . The cell arrangement is shown in FIG. 7. The horizontal cell 50, in which the gel for temporary isolation should be placed, contains an additional element located at its end 70 in the form of an insert 60a with a groove or in the form of a ceramic core 60b with a permeability of less than 1 mD. The groove insert is a model of a perforated formation. The ceramic core is a model of an unperforated formation. Unless otherwise specified in this example, then by default, an insert with a groove is used. The horizontal cell can, if necessary, be raised or lowered for installation at the desired angle using a jack 65. Pipeline 75 connects the bottom of the vertical cell 55 to the side of the horizontal cell 50. Pipeline 75 is a model of the inclined section of a horizontal well. A heater is placed around the horizontal cell to heat the cell and control the temperature. An increase in the temperature of the gel in a horizontal cell was carried out within a certain temperature range. The gel was pumped from a vertical cell 55 into a horizontal one, in the form of a suspension in tap water, through a pipeline with a pressure increase of up to 100 psi. inch. After the gel was pumped into a horizontal cell 50 and held for two hours at the crosslinking temperature, the vertical cell 55 was filled with colored tap water. Then, additional pressure was applied to the upper part of the vertical cell, while the volume of water coming from the vertical cell to the horizontal was used as an insulation measure. In addition, the amount of gel extruded through the groove of the insert was measured.

Example 7. This example illustrates the ability of a well treatment fluid of the present invention to act as a blocking agent for some time at a pressure corresponding to the pressure in an unperforated formation. The experimental procedure included obtaining the gel composition used in example 5 (500 ppt polymer and water with borax in a percentage by weight of 3% by weight of the polymer, buffered to a pH of 9.65 by adding a 10% sodium hydroxide solution ) The experimental conditions were the same as in Example 6, except that a ceramic core with a permeability of less than 1 mD was used. The gel was pumped from a vertical cell to a horizontal cell and heated to 250 ° F for two hours at a pressure of 100 psi. an inch for stitching it. The vertical cell was filled with colored tap water. Then, an additional pressure of 500 psi was applied to the top of the vertical cell for one hour. inch. After the first hour, there was no water breakthrough, indicating good insulation. The cell was then shut off overnight at a pressure of 500 psi. inch and opened again the next morning. There was no water breakthrough in this case either. Again, the pressure was increased in increments of 100 psi. inch up to 1000 psi inch. Before moving to the next level, each pressure value was maintained for 5 minutes in order to detect a possible breakthrough of water. At a pressure drop of 1000 psi. In., observing the cell for 6 hours showed no signs of water breakthrough. The cell was again shut off overnight at the same temperature and pressure. The next morning, the cell was reopened and observed for 24 hours at 1000 psi, with no water breakthrough. This example shows that the described gel is able to act as a blocking agent.

Example 8. This example illustrates the possibility of pumping a stimulating fluid through a blocking gel into a perforated formation. The experimental procedure included obtaining the gel composition used in example 5 (500 ppt polymer and water with borax in a percentage by weight of 3% by weight of the polymer, buffered to a pH of 9.65 by adding a 10% sodium hydroxide solution ) The experimental conditions were the same as in example 6, using the insert with a groove as a model of a perforated formation. The gel was pumped from a vertical cell to a horizontal cell and heated to 250 ° F for two hours at a pressure of 100 psi. an inch for stitching it. The vertical cell was filled with colored tap water. With increasing pressure up to 125 psi an inch there was a breakthrough of water as a result of the formation of a channel for its passage through the gel near the center of the gel bookmarks. This example shows that a stimulating fluid can be successfully pumped through a blocking gel into a perforated formation.

Example 9. A series of experiments was devoted to assessing the possibility of destruction of the gel after it has been worked out as a blocking material. The results are shown in tables 1 and 2. In these experiments, two different destructors at different concentrations were used. The experimental procedure included obtaining the gel composition used in example 5 (500 ppt polymer and water with borax in a percentage by weight of 3% by weight of the polymer, buffered to a pH of 9.65 by adding a 10% sodium hydroxide solution ) As shown in tables 1 and 2, the destructor was added to the gel. Thereafter, 400 ml of gel was introduced into the horizontal cell described above and heated to the indicated temperature at a pressure of 1000 psi. inch. Cells were periodically opened to control gel destruction. Table 1 shows the results of using the GBW-25 destructor, and Table 2 shows the High Perm CRB (encapsulated ammonium persulfate) destructor.

These results show the possibility of degradation of the gel and the variability of the time of destruction, which gives the present invention greater flexibility.

From the above description it follows that in the present invention, numerous changes and modifications are possible within its scope and essence.

Claims (36)

1. A method of conducting repeated hydraulic fracturing of an underground formation in which a well passes, having a number of zones, including: a) hydraulic fracturing of the productive zone inside the underground reservoir; b) isolating the productive zone subjected to hydraulic fracturing from the second zone in the well by (i) injecting the unhydrated borated galactomannan gum and a crosslinking agent into the well, moreover, the non-hydrated boron galactomannan gum contains borate ions before the transition to the crosslinked state, and (ii) the formation of thickened temporary compaction through the interaction of unhydrated borated galactomannan gum and a crosslinking agent, thereby isolating the productive zone subjected to hydraulic fracture, from the second zone; c) the destruction of the thickened temporary seal between the isolated production zone subjected to hydraulic fracturing, and the second zone by injecting a viscosity reducing agent into the well and lowering the viscosity of the thickened temporary sealing by reducing the viscosity, the viscosity reducing agent being pumped into the well under pressure, not sufficient to create or expand a fracture in a subterranean formation; and d) repeated hydraulic fracturing of the isolated productive zone subjected to hydraulic fracturing, after destruction of the thickened temporary seal by injection into the well of a hydraulic fracturing fluid under pressure sufficient to create or expand a crack in the isolated productive zone subjected to hydraulic fracturing. 2. The method according to p. 1, further comprising: e) injection into the borehole region of an isolated production zone subjected to repeated hydraulic fracturing of a well treatment fluid containing unhydrated borated galactomannan gum and a cross-linking agent, wherein the non-hydrated borated galactomannan gum contains borate ions before the crosslinked state; f) isolating the isolated production zone subjected to repeated hydraulic fracturing from another zone of the well by curing the well treatment fluid injected in step (e). 3. The method of claim 2, wherein steps (a) to (e) are repeated at least once. 4. The method of claim 1, wherein the well is a vertical well. 5. The method according to claim 1, wherein the viscosity reducing agent is an acid. 6. The method of claim 5, wherein the acid is selected from the group consisting of hydrochloric acid, formic acid, sulfamic acid, or a mixture thereof. 7. The method according to p. 1, in which the agent that reduces the viscosity, is a reagent that destroys the products of oxidation, or a reagent for the destruction of enzymes, or a combination thereof. 8. The method of claim 7, wherein the viscosity reducing agent is selected from the group consisting of alkaline earth metal peroxides, metal peroxides, organic peroxides, bleach, persulfates, chromium salts, sodium bromate, sodium perchlorate, sodium perborate, magnesium perborate, calcium perborate, galactomannanase and mixtures thereof. 9. The method of claim 1, wherein the subterranean formation is shale. 10. The method of claim 1, wherein the well is a horizontal well. 11. A method of conducting hydraulic fracturing of an underground formation in which a well passes, including: a) injection into the well of unhydrated borated galactomannan gum and a crosslinking agent; b) compaction of the productive zone subjected to hydraulic fracturing, relative to another zone in the well by means of a gel for temporary isolation due to the interaction of borated galactomannan gum and a crosslinking agent to form a gel for temporary isolation from the product of this interaction; c) injection of a viscosity reducing agent into the well, reducing the viscosity of the gel for temporary isolation, decompression of the productive zone subjected to hydraulic fracturing, relative to the other zone, and removing the gel for temporary isolation from the well, the viscosity reducing agent being pumped into the well under insufficient pressure to create or expand a fracture in a subterranean formation; g) conducting repeated hydraulic fracturing of the decompressed productive zone, exposing it to hydraulic fracturing, by supplying fluid to this zone for hydraulic fracturing under sufficient pressure to create or expand a fracture; and e) injection of unhydrated borated galactomannan gum and a cross-linking agent into the well and formation of a gel for temporary isolation between the zone subjected to repeated hydraulic fracturing and another zone through the interaction of unhydrated borated galactomannan gum and a cross-linking agent. 12. The method according to p. 11, including the re-execution of steps (a) - (e) in one or more productive zones of the well. 13. The method of claim 11, wherein the well is a vertical well. 14. The method of claim 11, wherein the viscosity reducing agent is an acid. 15. The method according to p. 11, in which the agent that reduces the viscosity is a reagent that destroys the products of oxidation, or a reagent for the destruction of enzymes, or a combination thereof. 16. The method of claim 11, wherein the well is a vertical well. 17. A method of increasing the productivity of the oil and gas reservoir in which the well passes, having a number of productive zones, including: a) the formation of a gel for temporary isolation between the zone previously subjected to hydraulic fracturing and the other zone by injection into the well of unhydrated borated galactomannan gum and a delayed crosslinking agent and their interaction; b) injection of a viscosity reducing agent into the well, reducing the viscosity of the gel for temporary isolation and then removing it from the well; c) injection into the well of a fluid for hydraulic fracturing under sufficient pressure to create or expand a crack in an underground formation, and repeated hydraulic fracturing of the productive zone previously subjected to hydraulic fracturing; g) injection into the well of a fluid for treating wells containing unhydrated borated galactomannan gum and a delayed crosslinking agent; and d) isolation of the productive zone, subjected to repeated hydraulic fracturing, by curing the fluid for treating wells containing unhydrated borated galactomannan gum and a delayed crosslinking agent. 18. The method according to p. 17, in which the agent that reduces the viscosity is an acid, or a destructor, or a combination thereof. 19. The method according to p. 17, in which the underground layer is a layer of shale. 20. The method according to p. 17, in which the well is a horizontal well.

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