BR102012002399A2 - aqueous composition for partially or totally blocking water production in production or injection wells and method of preparing said composition - Google Patents

Abstract

aqueous composition for partially or totally blocking water production in production or injection wells, and method of preparing said composition. An aqueous system and its preparation methodology are described to obtain partial or total blockage of water production in both producer and injector wells of the oil and / or gas industry, useful for blocking very permeable areas for the purpose of reduce water production and redirect its flow into the reservoirs, the system comprising low viscosity organic products to be pumped into the liquid well, and which after a certain period of time reach the desired gel consistency.

Description

Aqueous composition for partial or total blockage of water production in production or injection wells, and method of preparing said composition.

FIELD OF THE INVENTION The present invention relates to a composition or, as is known in the state of the art, a system to be applied for the treatment of oil and gas industry wells, and more particularly relates to a chemical composition for "water blocking" which allows the blocking of very permeable formation areas, reducing production and redirecting the flow of water injection into the reservoirs, being a versatile system capable of generating sealing or non-sealing gels according to with its composition to control water production.

DESCRIPTION OF PRIOR ART STATE

In the oil industry, "secondary recovery" techniques have been increasingly applied to improve hydrocarbon production. This technique involves injecting chemically treated water, which is injected through wells that are designed for this purpose in order to "sweep" or drag away residual oil trapped in the formation. As injected water generally has a viscosity that is lower than that of crude oil, and due to the innate heterogeneity of the reservoir, after a certain period of time the water is channeled through highly permeable zones, limiting treatment efficiency. This leads to high costs associated with treatment with production water, waste and water management, which makes secondary recovery not economically viable.

Given these limitations, several techniques have been developed to redirect the flow of injected water into the reservoir for treatment of formation that has not been properly processed. Most proposed systems involve pumping liquid organics into the wellbore, either an injection or production well, and after a certain period of time, such as hours or days, a hard gel is generated that creates a partial or full permanent seal on the most permeable layers of the treated formations. In this way, it is possible to redirect the injection water to the reservoir areas containing hydrocarbon reserves. These batch prepared blocking treatments are commonly known as "Water Shut-Off" (WSO) treatments, systems, or compositions. The purpose of this technique is to reduce water production. and costs associated with water separation processes in petroleum, and also aims to reduce equipment costs as well as costs generated by corrosion, tartar formation and sand production. enable you to reduce the amount of forming water extracted and re-injection costs while minimizing environmental impact.

Water blockage (WSO) treatments increase hydrocarbon production by increasing the explored reservoir area under secondary recovery. Therefore, they increase reservoir life, optimizing oil recovery. Water blocking technology is applied not only to wells during secondary recovery, but also to production wells with high natural brine cuts from aqueous zones.

There are currently many methods in use to control water production. One of the first methods used in the oil and gas industry was the application of calcium carbonate, sand or cement buffers. After that, new tools were developed to provide mechanical insulation or blockages, such as wrappers and jacketing patches. Recently, new chemical systems have also been developed, such as gel injection, resins, foamed fluids, emulsions and particulates, among others. Among the chemical methods, three techniques can be mentioned to optimize secondary recovery, or Secondary Oil Recovery. (known as Enhanced Oil Recovery (EOR)), or for water control: Water flood polymers. They are polymeric systems to increase water viscosity, and are used to improve the mobility ratio between water and oil by optimizing oil sweeping during water injection (water flooding). These systems are usually pumped through injection wells.

Relative Permeability Modifiers (MPR). These are hydrophilic polymer based treatments that are pumped into the formations, reducing water permeability without significantly affecting petroleum permeability. Although this type of treatment is applied directly to production wells, MPR-based systems have been proposed to treat injection wells. MPR-based systems generally have low viscosity and do not generate significant blockage of porous spaces.

Permeability blocking systems for water blocking. These systems are designed to partially or completely block formation, used to seal highly permeable formation channels where water is produced. These treatments are designed for both injection wells and producers. A low viscosity polymer solution is pumped within the formation, and once it is in the area to be treated, it becomes a rigid gel with dramatically increased viscosity. This creates a blocking effect on the most permeable layers where water is being produced.

Although permeability blocking systems have been shown to operate satisfactorily, they nonetheless have some weaknesses that could be improved with respect to, for example, the stability of the composition, which is often lost in the face of particular well conditions, to gel generation, may not be controlled as desired, and the ability to remove the lock when necessary within certain time limits, which is not possible with currently known blockers.

BRIEF DESCRIPTION OF THE INVENTION It is therefore an object of the present invention to provide a novel aqueous composition, or system as known in the state of the art, to block water, allowing blockage of very permeable formation areas, reducing production and redirecting the water. injection water flow into the reservoir, a composition comprising relatively low viscosity organics to be pumped into the injection or liquid production well, and after a certain period of time such as hours or days, reaches the desired consistency according to the needs of each treatment, where the gel formed does not destabilize in the presence of salt in water. It is yet another object of the present invention to provide a new aqueous well treatment composition for the oil and gas industry which may range from a rigid gel used as a sealant to produce complete blockage of water flow into the well. , even a deformable gel, which produces only a partial blocking effect, significantly reducing water passage but allowing oil passage, where such compositions or treatments may be prepared in batches or portions and are called Water Block treatments ( known as WSO), and can be removed from the well within a certain time. It is a further object of the present invention to provide an aqueous composition for partially or totally blocking water production in producer or injector wells, wherein the composition comprises a mixture of: a) partially hydrolysed polyacrylamide or polyacrylamide of 0.1 MDa <Mw < 20 MDa; b) an alkoxysilane compound having two or more amino groups attached to a substituent R used as a crosslinking agent; and c) an organotitanate used as an accelerator. It is a further object of the present invention to provide an aqueous composition for partially or totally blocking water production in producing or injector wells, where the organo-silicon compound of the mixture in question is an N- (paminoR) -y-aminoR 2 trialkoxysilane where R may be alkyl or aryl groups and OX are alkoxy groups: It is also an object of the present invention to provide an aqueous composition for partially or totally blocking water production in producer or injector wells, where the organotitanate compound of said mixture It is an acetylacetonate chelate titanate, lactic acid chelate ammonium salt titanate, triethanolamine titanate chelate, or a mixture of chelates with at least one component containing the following structure: It is also an object of the present invention to provide a method for preparing A composition as described in claim 1, characterized in that it comprises the steps of: Preparing brine or strong KCI saline according to the volume of treatment to be pumped;

Under vigorous stirring, add the polymer to the previously prepared saline solution, stirring to constant viscosity and transparent appearance. Then add the titanate and then the crosslinking agent in the desired amounts, and stir until complete dispersion.

BRIEF DESCRIPTION OF DRAWINGS

For the sake of clarity and understanding of the present invention, it has been illustrated in various figures, in which the invention has been represented in some of the preferred embodiments, all by way of example, where: Figures 1 to 6 are graphs showing the initial gelation time (Tgi) at 45 and 65 ° C, evaluated at a shear rate of 30 s', these graphs indicating the influence of crosslinking agent and accelerator concentration on the initial aqueous solutions. Figure 7 shows the pumping sequence used in the test, where the variation of permeability for each fluid is a function of time.

- Figure 8 is a graph showing variations of the Residual Resistance Facfor (RRF) for oil and water as a function of applied pressure gradient, expressed in psi / foot. Figure 9 shows a possible reaction mechanism between the polyacrylamide and the crosslinking agent. Figure 10 depicts the most likely reaction mechanism between polyacrylamide, crosslinking agent and accelerator (titanate chelate). - Figure 11 shows a reaction with the formation of esters and generation of a three-dimensional network composed of polymer and titanate.

DETAILED DESCRIPTION OF THE INVENTION The water block composition of the present invention comprises the use of a medium to high molecular weight aqueous polymeric solution, such as partially hydrolyzed and unhydrolyzed polyacrylamide, and an organosilane family crosslinking agent containing two or more more amino groups arranged on the same substitute silane Rn. The composition, or system, as also known in the state of the art, contains accelerators in varying concentrations to increase the reaction range and final consistency of the gel formed, depending on the treatments required for each specific well and the formation under intervention. Such accelerators are organotitanate chelates or also tetraalkylthitanates. The invention comprises a versatile composition of the water blocking system which can generate sealing or non-sealing gels for use in both producing and injection wells as well as treatments for controlling water production. The versatility of the composition is based on the possibility of forming gels of different consistency from varying concentrations of polymer, preferably polyacrylamide, cross-linking agent, preferably organosilanes, and accelerators such as organotitanates, as well as from variations. of molecular weight and degree of hydrolysis of the polyacrylamide used.

According to the invention, three-dimensional networks are formed from the reaction between polyacrylamide at concentrations ranging from 0.3 to 4% in the aqueous solution, a crosslinking agent from 0.1% to 3% v / v, and An accelerator. The initial viscosity of the polymer solution is low, about 20 cp @ 300 rpm. This condition is essential to avoid high injection pressures that could fracture the treated formation. The accelerator may be present at concentrations greater than 0 to 5% v / v, depending on the response range or speed and the required consistency.

Preferably, the composition of the invention comprises a linear polymeric aqueous solution of unhydrolyzed polyacrylamide (PAM) or sparingly hydrolyzed polyacrylamide (HPAM), with molecular weight values between 0.1 and 20 MDa, a crosslinking agent or cross-linking agent. A family of alkoxysilanes containing two or more amino groups in their structure. These compositions may contain accelerators or synergists capable of accelerating gel generation as well as their final consistency. The above synergizers are organic titanate chelates as well as tetraalkylthitanates.

As an example, a representative composition of the invention is presented: 0.3 to 4% w / v PAM (polyacrylamide) or HPAM (0.1 <Pm <50 MDa); 0.1 to 3% v / v reactive sialian (crosslinking agent); 0 to 5% v / v titanate (synergizer); 0 to 2% v / v KCI, and 86 to 99.6% water.

Hydrolyzed organotitanates are used as a crosslinking agent or crosslinker of a wide variety of polymers, such as silicone. As a result, the final gel structure is quite rigid compared to the same structure in the absence of titanate.

Among the possible alkoxysilanes tested as crosslinking agents, the most suitable is one containing two or more amino groups in its structure, of formula RnSiX4-T „where R is alkyl or aryl, non-hydrolysable groups, functionalized with 2 or more amino groups arranged on the same substituent Rn. Such groups are those which, by chemical compatibility, interact with polyacrylamide. Alkoxy groups are represented by X, and may be methoxy or ethoxy, which may be hydrolyzed by releasing alcohols to the medium to form silanols. Silanols may react with the accelerator to improve the properties of the WSO composition.

Another advantage of using silanes in the present invention is their strong interaction with silicates and other minerals present in the reservoir rock. This effect has been widely used in the oil and gas industry for migration control. This same effect increases the bonding or adherence of the WSO composition to the reservoir rock, so securely fixing the WSO gel to the formation, avoiding the exploration processes.

Referring first to Figures 9 to 11, Figure 9 shows a possible reaction mechanism between the polyacrylamide and the crosslinking agent. It is understood that the gelling process should be performed in four associated steps. The first involves hydrolysis of the alkoxy (X) groups of the sialian. Immediately after hydrolysis, the silanols thus formed condense together, eliminating water. However, when heated in a basic medium (which is created by the presence of amino groups in the silanes) the polyacrylamide is partially hydrolyzed and the formed carboxylates interact electrostatically with the amino groups present in the silanes. Figure 10 depicts the most likely reaction mechanism between polyacrylamide, crosslinker and accelerator (titanate chelate). In the basic medium, hydrolysis of titanates is much slower than in acidic medium. The alkoxititanate formed in hydrolysis is very reactive, rapidly combining with silanes, but amino groups continue to interact electrostatically with polyacrylamide carboxylate groups, as described above.

The gels obtained in this way are much stronger than those obtained for formulations without titanates. Comparing figures 1 to 5, it is possible to verify that the gelation time decreases in the presence of titanates.

In basic medium (pH = 12 to 14) and in the absence of silane, but in the presence of titanates, there is an increase in viscosity but no gel formation. Therefore, a titanate molecule must interact with both the carboxylates formed by polyacrylamide hydrolysis and other hydrolyzed titanate molecules to condense the molecules together. Such reactions are by no means rapid, occurring only after several hours.

In acid medium in the presence of silane and polyacrylamide, there is no gel formation, which justifies the idea that the interaction between polymer and silane is through the silane amino groups. These groups are protonated into an acid, which prevents them from interacting with the carboxylic groups formed with polyacrylamide hydrolysis. However, if titanate is added to said acid medium, it rapidly hydrolyzes and the formed hydroxyl groups interact with the polyacrylamide carboxylic groups, with the formation of esters and generation of the three-dimensional polymer and titanate network (Figure 11).

When the polyacrylamide, silane and titanate composition is conditioned to pH = 7 and subjected to a temperature of 65 ° C, no gel formation is observed during the 1 week test period.

An additional advantage of this composition is the ability to reverse the blocking action within the first 15 days after preparation if the gel is treated with a 0.06% w / v solution of a strong oxidant such as ammonium persulfate or hypochlorite. sodium Since the WSO gel has exceeded 15 days, the treatment cannot be attacked by oxidizing agents or extreme pH values. The system without addition of bases or acids has been shown to have the same or better properties as existing sealing or non-sealing water block gels. Depending on the formulations, highly deformable non-fluid gels (A) to rigid gels (F) can be obtained. Gelling time may range from a few hours to more than two days, depending on the concentration and type of polymer, crosslinking agent concentrations, accelerator and temperature. Another advantage of this composition is that at room temperature the gelation time is very long, from 1 to 2 weeks. This difference in reaction rate with temperature allows the system or composition to be more versatile during mixing and pumping procedures, eliminating the risk of unwanted premature gelation. The following list shows the letter codes used for the consistency classification of WSO gels: Code List: A: Fluid Only Gel. The gel slowly flows to the top of the bottle. A significant portion of the gel does not flow by inversion of the container. B: Highly deformable non-fluid gel. The gel does not flow by inversion of the container. C: Moderately deformable non-fluid gel. D: Slightly deformable non-fluid gel. Only the surface deforms by inversion. E: Hard gel. The surface does not deform by inversion. F: Very hard gel. A mechanical vibration, similar to a tuning fork, can be felt when the container is struck lightly. G: Fluid gel. H: Viscous liquid.

This invention is best illustrated by the following examples, which should not be construed as a limitation. On the contrary, it should be clearly understood by reading this disclosure that other embodiments, modifications and equivalents may occur to those skilled in the art without departing from the spirit of this invention and / or from the fulfillment of the appended claims.

Examples WSO rheological behavior. The behavior of systems or compositions that vary polymer concentration as well as crosslinking agent and accelerator concentrations have been rheologically evaluated. Gel consistency was found to change as a function of time, temperature and component concentrations. The graphs of Figures 1 to 6, applied by way of example in the present invention, show the influence of crosslinking agent and accelerator concentration on the initial aqueous solutions. Measurements were made using an OFITE 900 type viscometer at temperatures from 25 to 65 ° C.

The graphs show the initial variation of ge! over time (Tgi) at 45 and 65 ° C, assessed at a shear rate of 30 s "1. Approximate molecular weight of MAP is 8 MDa, Example 1: Viscosity versus time plot @ 65 ° C (figure 1) 0.7% PAM 0.7% PP-20 1% XLB 2% KCI

Example 2: Viscosity versus time plot @ 65 ° C (Figure 2) 1% PAM 0.7% PP-20 1% XLB 2% KCI

Example 3: Viscosity versus time plot @ 65 ° C (Figure 3) 1% PAM 1% PP-20 1% XLB

2% KCI

Example 4; Viscosity versus time plot @ 65 ° C (Figure 4) 0.7% PAM 0.7% PP-20 2% XLB 2% KCI

Example 5: Viscosity versus time plot @ 65 ° C (Figure 5) 0.7% PAM 0.7% PP-20 2% KCI

Example 6: Viscosity versus time plot @ 45 ° C (Figure 6) 1% PAM 1% PP-20 2% KC!

The results of the above examples show that the initial gel time depends on the polymer, crosslinking agent and accelerator concentrations as well as the temperature at which the composition is subjected.

According to the invention, a method for preparing the composition of the described water block system is proposed, wherein the method comprises the following steps: 1) Preparing brine or a KCI saline solution according to the treatment volume to be treated. pumped; 2) Under vigorous stirring, add the polymer to the previously prepared saline solution. Shake for approximately 2 hours until constant viscosity and transparent appearance - the polyacrylamide granules should be completely hydrated. 3) Add the titanate and then the crosslinking agent (PP-20) in the desired amounts, and stir until complete dispersion.

WSO Sealant Behavior

This section presents the laboratory tests performed in accordance with the selected WSO formulations of the present invention, demonstrating the sealing and partial sealing action of the system.

Evaluation Methodology The efficiency of WSO treatment was evaluated by flow testing on Berea sand samples with known permeability formation.

The samples were 3.8 cm in diameter and 7 cm in length. The tests were performed simulating the following reservoir conditions, 65 ° C and 1,500 psi (105.45 kg / cm2) confinement pressure. Table 1 shows the properties of the samples used in the flow assays.

Table 1 2-API water was filtered (5 wt% NaCl + 2 wt% KCl + 1 wt% CaCl2). The hydrocarbon system used was diesel oil. Both fluid systems were injected in the production direction. The water-saturated sample was mounted inside the Chandíer 9000 Formation Response Tester (FRT) cell, and was packaged at confinement temperature and pressure.

For each case, flow rate (flow) and differential pressure were measured on both sides of the sample. Each fluid was pumped at different flow rates, starting at the lowest possible value (in some cases below 0.01 ml / min). Once stability was achieved, the flow was increased gradually, taking into account pumping pressure limitations.

Once the sample was assembled on the equipment, the directions of production and injection flow were defined. The pumped fluids were: 1. Hydrocarbon prior to WSO (Kopre) treatment. Hydrocarbon permeability to irreducible water saturation (KoWj) was used as a reference for comparing hydrocarbon permeability after polymer injection. 2. Saline before treatment with WSO (Kwpre). Water permeability (2-API) to residual hydrocarbon saturation (Kwor) was used as a reference for comparing water permeability after polymer injection. 3. WSO polymer injection at 0.5 ml / min in the injection direction. The typical injected volume was 5 PV (pore volumes). It was then allowed to rest for 24 hours. 4. The hydrocarbon was pumped again in three flows (similar to the initial one). Based on the measured pressure differential values for each flow rate, the mean post-treatment hydrocarbon permeability (Kopos) was determined.

Finally, the 2-APi saline was pumped in the production direction at three different flow rates to obtain the average post-treatment water permeability (Kwpos) - the Residual Permeability Resistance Factor (RRF). water or oil was determined as follows: Where: Kpre and Kpos are the hydrocarbon or water permeability, pre- or post-treatment WSO measurements; μρΓβ, ppPs are the viscosities (of diesel or water) before and after treatment. In these tests, μρΓ6 = μρο $ · Based on the flow tests, the RRFw and RRFo values were determined.

Results The results of the flow tests performed on Berea formation and sand samples treated with the WSO composition are as follows: Berea sand assay. Bearing in mind that the Berea sand test has a lower permeability and porosity compared to the formation sample, a partially blocking WSO system or composition was used. This system ensures adequate matrix penetration of the treatment into the rock as well as strong adhesion to it even at high flow speeds. Figure 7 shows the pumping sequence used in the test, where the variation of permeability for each fluid is shown as a function of time. Table 2 summarizes the average permeability values, pre- and post-treatment, measured for water and hydrocarbon and their corresponding RRF residual resistance factors.

Table 2 Test with formation sample. Considering that the formation sample presents higher permeability and porosity than the previously tested Berea sample, a WSO-like composition was selected. This system or composition has good penetration, acquiring high rigidity once activated. Table 3 summarizes the average pre- and post-treatment permeability values measured for water and hydrocarbon and their corresponding RRF residual resistance factors.

Table 3 Polymer adhesion. For the purpose of evaluating the degree of bonding or adherence of the gel to the formation, a study was performed during the Berea sand sample flow test. This study evaluated the maximum pressure gradient that the system or composition could support. Differential pressure was applied to the base buffer, while pumping of reference fluids (2-API saline and diesef oil) was gradually increased, resulting in extreme flow conditions that could suppress treatment. Based on the data obtained in this test, it can be seen in figure 8 the variations of RRF for oil and water as a function of applied pressure gradient, expressed in psi / foot. This figure shows that the WSO treatment or composition of the present invention is not swept or dragged from the sample even if the pressure gradient is 1,000 psi / foot. The relationship between RRFw and RRFo remains in the same range (RRFw / RRFo = 6). Similar behavior was observed when the formation samples were tested. In this case, the RRFw / RRFo ratio was maintained between 10 and 11.5, WSO lock removal.

As part of the study using a sample from a formation, once the test was completed, a specific removal treatment based on oxidizing agents was injected. This treatment has resulted in an advantage for the present WSO composition or treatment as it allows to recover part of the original permeability of the treated formation sample within the first 15 days after placement. The oxidizing treatment is injected into the sample (1.5 pore volumes), allowing it to act for 2 hours. Then the saline solution was injected at different flow rates in the production direction to determine the degree of permeability recovery. After system injection or removal composition, the mean value Kw increased by a factor of 6 over the reference value Kwpos (from 0.006 to 0.036 mD). Therefore, RRFw has decreased from 10,935 to approximately 1820. The WSO composition or system of the present invention is suitable for a wide range of operating conditions, such as compositions and petrophysics of formations, temperature, pressure, etc., which are found in reservoirs. Additional advantages of this system or composition may include: 1. The presence of salt in water does not destabilize the gel that is formed; 2. The gel may be removed using aqueous strong oxidizing solutions.

Claims

Claims (15)

Aqueous composition for partially or totally blocking water production in production or injection wells, characterized in that the mixture comprises: a) polyacrylamide or partially hydrolyzed polyacrylamide; b) an alkoxysilane compound having two or more amino groups attached to a substituent R used as a crosslinking agent; and c) an organotitanate used as an accelerator, Aqueous composition according to claim 1, characterized in that the concentration of PAM in the aqueous solution is between 0.3 and 4% w / v. Aqueous composition according to claim 1, characterized in that the concentration of alkoxysilane compound is about 0.5 to 3% w / v. Aqueous composition according to claim 1, characterized in that the concentration of alkoxititanate compound ranges from 0 to 2% w / v; Aqueous composition according to claim 1, characterized in that the viscosity of the initial polymer solution should not exceed 50 cp @ 300 MPR. Aqueous composition according to claim 1, characterized in that the final viscosity must not be less than 800 cp. Aqueous composition according to claim 1, characterized in that the organo-silicon compound is an N- (paminoR) -y-aminoR 2 trialkoxysilane, where R may be alkyl or aryl groups, and OX are alkoxy groups. : Aqueous composition according to claim 1, characterized in that the organotitanate compound is an acetylacetonate thitanate chelate, lactic acid chelate ammonium salt titanate, triethanolamine titanate chelate or a mixture of chelates with at least a component that contains the following structure: Aqueous composition according to claim 1, characterized in that the water biochemical macromolecule has a molecular weight between 0.1 MDa and 20 MDa. Aqueous composition according to claim 8, characterized in that the macromolecule is polyacrylamide and / or polyacrylamide with a maximum degree of hydrolysis of 50%. Aqueous composition according to claim 1, characterized in that RRFw values above 20 are obtained in formation samples. Aqueous composition according to claim 1, characterized in that it is injected into formations with varying petrophysical properties (porosity and permeability), ensuring adequate matrix penetration and high efficiency once the gel is formed. Aqueous composition according to claim 1, characterized in that it is not swept from formation even at pressure gradients greater than 1,000 psi / foot (70.3 kg / cm2). Aqueous composition according to claim 1, characterized in that it is partially removable with the use of specific oxidizing agents (persulfate and hypociorite) if it is necessary to remove the formation blockage during the first 15 days after its formation. placing. Method of preparing an aqueous composition for partially or totally blocking the production of water in production or injection wells according to claim 1, comprising the steps of: - Preparing brine or a saline solution of KCI according to the volume of treatment to be pumped; - Under vigorous stirring, add the polymer to the previously prepared saline solution until constant viscosity and transparent appearance are obtained; Add titanate and then the crosslinking agent in the desired amounts, stirring until complete dispersion.