Scale treatment in a heterogeneous reservoir using a non-newtonian fluid

Abstract

The technology relates to a method of treating inorganic scale in a well that is drilled in a heterogeneous reservoir matrix. A heterogeneous reservoir matrix has varying permeabilities. The varying permeabilities can cause a change in the shear rate as a fluid flows through it. A shear thinning nanofluid that includes a nanoparticle functionalized with a scale inhibitor and an aqueous solvent is injected into the heterogeneous reservoir matrix. The shear thinning behavior of the nanofluid causes a self-diversion of the nanofluid from a high permeability zone towards the low permeability zone due to a change in the viscosities. The self-diversion causes the scale inhibitor to be delivered to the low permeability zone.

Description

TECHNICAL FIELD

[0001] This disclosure relates to methods of scale treatment in a well.BACKGROUND

[0002] The formation of inorganic scale (calcium carbonate, magnesium carbonate, calcium sulfate, and barium sulfate) in oil and gas production equipment or within the reservoir is a common problem. The deposition of scale on tubular surfaces reduces the fluid flow. Scale inhibitor squeeze (SIS) treatment is the most commonly used method to protect oil and gas production systems from inorganic scale deposition. One of the major challenges of SIS treatment is the treatment of scale formation in wells producing from heterogeneous reservoir formations. Heterogeneity in reservoir formations occurs due to contrasting permeabilities, changes in porosity, and changes in rock compositions. The heterogeneity contributes to an uneven placement of scale inhibitor in the reservoir by SIS treatment.

[0003] Methods to circumvent the uneven placement of the scale inhibitor often rely on expensive coiled tubing operations, temporary shut-off of high permeability zones, or overdosing some zones to gain placement in other zones, especially in lower permeability zones. Each of these methods has drawbacks which can limit its applicability. The costs associated with such treatments are high and are often prohibitive when compared to conventional bullhead operations. Thus, there is a need for a method of placing the scale inhibitor evenly, especially in the lower permeability zone, using the bullhead pumping operations.SUMMARY

[0004] The present disclosure provides a method for scale treatment. In some implementations, the method includes pre-flushing a heterogeneous reservoir matrix with a solvent, where the solvent is injected through a well; injecting a nanofluid into the heterogeneous reservoir matrix through the well, where the nanofluid includes a nanoparticle functionalized by loading with a scale inhibitor and an aquifer water; self-diverting the nanofluid by a shear thinning behavior of the nanofluid, from a high permeability zone to a low permeability zone of the heterogeneous reservoir matrix; shutting in the well for a time period to enhance retention of the scale inhibitor in the nanofluid, by the heterogeneous reservoir matrix; and resuming a production of a plurality of fluids through the well.

[0005] In some implementations, the nanoparticle includes a metal oxide functionalized with a scale inhibitor.

[0006] In some implementations, the nanoparticle includes a carbon nanotube or graphene oxide loaded with a scale inhibitor.

[0007] In some implementations, the nanoparticle includes a scale inhibitor and a divalent cation.

[0008] In some implementations, the nanoparticle includes a carboxyl-modified quantum dots (CCQDs).

[0009] In some implementations, the scale inhibitor includes amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters

[0010] In some implementations, the shear thinning behavior of the nanofluid enhances the flow of the nanofluid into the low permeability zone.

[0011] In some implementations, the nanofluid in the low permeability zone comprises a low viscosity at a high shear rate

[0012] In some implementations, the method includes measuring a concentration of the scale inhibitor in the plurality of fluids from the well, where the scale inhibitor comprises a minimum effective concentration (MEC).

[0013] In some implementations, when the concentration of the scale inhibitor falls below the MEC, the nanofluid is reinjected into the well.

[0014] In some implementations, shutting in the well includes the time periods of 4-50 hours.

[0015] Implementations described here provide a method of scale inhibitor displacement in a heterogeneous reservoir. In some implementations, the method includes injecting a nanofluid into the heterogeneous reservoir through a well, where the nanofluid includes a nanoparticle functionalized by loading with a scale inhibitor and an aqueous solvent; self-diverting the nanofluid into the heterogeneous reservoir by a non-Newtonian characteristic, where the non-Newtonian characteristic includes a shear thinning behavior of the nanofluid; and producing, through the well, a produced water stream from the heterogeneous reservoir that includes the scale inhibitor.

[0016] In some implementations, the nanoparticle includes a metal oxide functionalized with a scale inhibitor and an aquifer water.

[0017] In some implementations, the scale inhibitor includes amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.

[0018] In some implementations, the scale inhibitor includes DETPMP or phosphate esters.

[0019] In some implementations, the nanofluid has a viscosity ranging between 100-2500 cP measured by a spindle ranging between 10-100 rpm.

[0020] In some implementations, the heterogeneous reservoir includes a high permeability zone and a low permeability zone.

[0021] In some implementations, the shear thinning behavior of the nanofluid causes a flow of a high viscosity nanofluid in the high permeability zone and a low viscosity nanofluid in the low permeability zone, caused by a difference in a shear rate.

[0022] Implementations described here provide a system for scale treatment. In some implementations, the system includes a heterogeneous well through which a shear thinning nanofluid is injected into a subterranean formation that includes a varying permeabilities, where the varying permeabilities causes a self-diversion of the shear thinning nanofluid into a low permeability zone; and a bullhead pump, which is used to pump the shear thinning nanofluid into the heterogeneous well.

[0023] In some implementations, the shear thinning nanofluid includes a metal oxide nanoparticle functionalized with a scale inhibitor and the aqueous solvent includes an aquifer water.BRIEF DESCRIPTION OF DRAWINGS

[0024] FIG. 1 is a graphical representation of a scale inhibitor's lifetime during a SIS treatment.

[0025] FIG. 2 is a graphical representation of a shear thinning fluid.

[0026] FIG. 3 is a schematic representation of a flow pattern near the wellbore.

[0027] FIGS. 4A and 4B represent scale inhibitor slug displacement in a heterogeneous reservoir using a bullhead pump.

[0028] FIG. 5 shows the test results of a scale inhibitor nanofluid that demonstrates shear thinning rheology.

[0029] FIG. 6 is a graphical summary of the rheological behavior of the nanofluid described in FIG. 5.

[0030] FIG. 7 is a process flow diagram of injecting a nanofluid that includes a scale inhibitor for SIS treatment in a heterogeneous reservoir.DETAILED DESCRIPTION

[0031] The application of chemical scale inhibitors to treat scale formation is the most effective method in oil and gas production operations. Chemical scale inhibitors are applied by scale inhibitor squeeze (SIS) treatment. The term “squeeze” refers to injecting a chemical scale inhibitor (hereafter referred to as scale inhibitor) into the wellbore of the producing oil or gas well to place the scale inhibitor into the reservoir zone without causing well fracturing.

[0032] In a heterogenous reservoir zone there is a permeability contrast, such as a high permeability zone in some regions and a low permeability zone in other regions. A permeability contrast causes the scale inhibitor to be placed unevenly, especially in heterogeneous reservoir rocks with long reach horizontal wellbores (with length >1000 ft.). The heterogeneity, crossflow, and pressure gradients between otherwise non-communicating zones within the well contribute to an uneven placement of the scale inhibitor during SIS treatment. This may result in most of the scale inhibitor being placed in an inappropriate zone near the wellbore region, which can result in reduced SIS lifetimes.

[0033] Disclosed herein is a method of using a scale inhibitor in the form of a nanofluid for squeeze treatments. The nanofluids are made up of nanoparticles. The nanoparticles are loaded with scale inhibitor molecules. The nanoparticles are formed either by adsorption or a precipitation reaction. The following description provides details for the use of a nanofluid in SIS treatment.

[0034] FIG. 1 is a graphical representation of a scale inhibitor's lifetime during SIS treatment. SIS treatment includes a sequence of steps for effective scale treatment that involves injecting fluids through a well that is formed in a subterranean zone. The well can include a vertical well or a horizontal well. In some implementations, the first step includes a pre-flush, which is also called a spearhead step. The pre-flush is performed to alter the rock surface for enhancing the scale inhibitor interactions with the reservoir rock. In some implementations, the pre-flush solvent includes an aqueous solution. In some implementations, the aqueous solution is a salt solution, such as a KCl solution, seawater, or aquifer water. In some implementations, the pre-flush solvent is an aqueous solution that includes a mutual solvent. In some implementations, the pre-flush solvent is an aqueous solution that includes a small amount of surfactant and scale inhibitor. In some implementations the pre-flush solvent includes aquifer water with ethylene glycol monobutyl ether (EGMBE). In some implementations, the pre-flush solvent includes about 90% aquifer water with about 10% EGMBE. In some implementations, the pre-flush solvent includes aquifer water with a demulsifier and a scale inhibitor. In some implementations, the pre-flush solvent includes aquifer water with about 0.5%-2 wt % demulsifier and about 0.05%-0.2 wt % scale inhibitor.

[0035] In some implementations, the second step is a main pill (a scale inhibitor slug) step. In this step, a diluted scale inhibitor solution is injected into the formation. In some implementations, the concentration of the scale inhibitor in the diluted scale inhibitor solution is about 1-50%. In some implementations, the scale inhibitors include amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.

[0036] In some implementations, the third step is an overflush step. In the overflush step, the scale inhibitor is placed at the desired depth from the wellbore. This is mainly to increase the interactions between the reservoir rocks and the injected scale inhibitor, which can result in an increase in the scale inhibitor retention by the reservoir rock. The displacement process can be conducted from the surface by a bullhead pump or by selective fluid placement by utilizing coil tubing.

[0037] In some implementations, the fourth step includes a tubing displacement step. This step is performed to fill the production tubing with a fluid to prevent corrosion damage to the tubing. Additionally, the selected fluid can prevent gas hydrate formation during the shut-in period. In some implementations, the fluids used to fill the production tubing include diesel, filtered crude oil, or treated seawater with methanol or glycols.

[0038] In some implementations, the fifth step includes a well shut-in period. In some implementations, the shut-in period lasts for hours to days. In some implementations, the shut-in period lasts from about 4-50 hours. The well undergoes a shut-in period to enhance the scale inhibitor retention by reservoir rocks, by either adsorption or precipitation reactions.

[0039] In some implementations, when the well production resumes, the scale inhibitor is gradually released into the produced water at levels above a critical level. This critical level is known as the minimum effective concentration (MEC) as shown in the figure. The MEC is desired to prevent solid (inorganic scale) deposition in the production system.

[0040] In FIG. 1 the lifetime of a scale inhibitor after SIS treatment is shown. It shows that the injected scale inhibitor initially returns at a very high concentration, which is higher than the MEC. After the initial high concentration, the scale inhibitor concentration drops off quickly within a short time. In some implementations, the drop off in scale inhibitor concentration occurs in the order of weeks. In some implementations, this could be in the order of days. Thereafter, the scale inhibitor concentration decreases slowly.

[0041] Squeeze life is the period of time for the return scale inhibitor concentration to reach the MEC level. In some implementations, a re-squeeze scale inhibitor treatment is performed once the scale inhibitor concentration falls consistently below the MEC. The squeeze life depends on the scale inhibitor retention and release properties of the reservoir rock and the water / oil production rates of the well. In some implementations, SIS treatment can provide protection near the wellbore zones, the tubing, and all the way to the topside facilities of the production well.

[0042] FIG. 2 is a graphical representation of a shear thinning fluid. The methods of the present disclosure use a nanofluid, which exhibits a non-Newtonian rheology, i.e., the viscosity of the fluid decreases with shear rate (or flow rate). These types of fluids are known as shear-thinning. The non-Newtonian characteristic of the nanofluid makes it suitable for SIS treatment in wells that produce hydrocarbons from a heterogeneous reservoir zone. The use of a nanofluid can improve the displacement of the scale inhibitor, while using a bullhead pump, instead of an expensive coiled tubing.

[0043] In some implementations, the nanofluids are made up of nanoparticles loaded with scale inhibitor molecules. The nanoparticles can be formed either by adsorption or a precipitation reaction. Examples include nanoparticles formed by a precipitation reaction between scale inhibitor and a divalent cation, such as calcium. In some implementations, the nanoparticles also include carbon nanotubes or graphene oxide (GO) loaded with scale inhibitor molecules. In some implementations, metal oxides such as calcium oxide, iron oxide, or aluminum oxide loaded with scale inhibitor molecules are used. In some implementations, the nanoparticles include quantum dots scale inhibitors such as, carboxyl-modified carbon quantum dots (CCQDs).

[0044] FIG. 3 is a schematic representation of a flow pattern near the wellbore. A well is drilled into the subterranean formation where it defines a hole known as a wellbore. The wellbore encouters various production zones across the reservoir rock. The production zones have varying permeability due to the heterogeneous nature of the reservoir rocks.

[0045] During SIS treatment, the injected nanofluid experiences a radial flow patten 302 as shown in FIG. 3. As the nanofluid moves further away from the wellbore, the corresponding linear flow rate decreases as the distance from the wellbore increases. This is shown in the graphical representation 304. As the nanofluid further flows into the reservoir rock, it encounters varying permeabilities. The varying permeabilities cause varying shear rates during flow. The nanofluid, which is shear thinning, experiences a change in viscosity during flow through the heterogeneous reservoir rock.

[0046] FIGS. 4A and 4B represent scale inhibitor slug displacement in a heterogeneous reservoir using a bullhead pump. In FIG. 4A a heterogeneous reservoir rock is schematically represented by two zones, a high permeability zone 404 and a low permeability zone 406. If a Newtonian scale inhibitor slug 402 (i.e., the viscosity does not change with shear rate) is flowed through this heterogeneous reservoir zone, the scale inhibitor slug 402 prefers the path of least resistance. Therefore, most of the scale inhibitor slug 402 enters the high permeability zone 404, where the pressure is low. A very small volume of scale inhibitor solution enters the low permeability zone 406 as it experiences a high pressure. The low permeability zone 406 gets less protection from scale formation. Pressure gradients or crossflow also influence the placement of the scale inhibitor slug, with injection being favored in the lower pressure zones. In reservoir zones with high heterogeneity and / or strong crossflow, injection may even fail to penetrate the low permeability zone.

[0047] To divert the scale inhibitor slug from its favoured flow path (high permeability zone) into a less favoured zone (low permeability zone), the fluid flow can be restricted in the high permeability zone to facilitate flow into the low permeability zone. To restrict the fluid in the high permeability zone, the fluid viscosity can be increased in the higher permeability zone and / or the fluid viscosity can be decreased in the lower permeability zone. This method diverts more fluid into the lower permeability zone. The shear-thinning property of nanofluids causes a self diversion of the nanofluid while using a bullhead pump.

[0048] In FIG. 4B, the heterogeneous reservoir rock is represented by two zones, a high permeability zone 404 and a low permeability zone 406. The nanofluid 408 is injected into the heterogeneous reservoir rock. The high permeability zone 404 has a low shear rate, and the low permeability zone 406 has a high shear rate. For a non-Newtonian fluid, such as a shear thinning fluid, the shear rate of a fluid varies inversely as the permeability of the transmitting medium. The difference in the shear rate causes the shear thinning fluid to change its viscosity.

[0049] The nanofluid, a shear thinning fluid, experiences a high viscosity in the high permeability zone 404, as the shear rate in this zone is low. Therefore, the high viscosity nanofluid blocks the high permeability zone 404. Following this, the nanofluid is self-diverted into the low permeability zone 406. In the low permeability zone 406, the shear rate is high and so the viscosity of the nanofluid is low. This increases the flow of the nanofluid 408 into the low permeability zone. This method of self-diversion of the nanofluid into the low permeability zone 406 occurs due to its shear thinning property. This increases the scale inhibitor slug displacement in the lower permeability zone 406.

[0050] The scale inhibitors are displaced near the wellbore region, after the overflush step. In some implementations, the scale inhibitor slug is displaced about 2-4 ft from the near-wellbore region for horizontal wells. In some implementations, the scale inhibitor slug is displaced about 5-7 ft from the near-wellbore region for vertical wells. In some implementations, the scale inhibitor slug is displaced about 4-6 ft from the near-wellbore region for deviated wells.

[0051] FIG. 5 shows the test results of a scale inhibitor nanofluid that demonstrates shear thinning rheology. In the test, a nanofluid was formed by mixing 50% of a nanoparticle functionalized with a scale inhibitor labeled as SI1313 (from Tomson Technologies LLC) and 50% Wasia aquifer water. The composition of the Wasia aquifer water is presented in Table 1. SI1313 included metal oxide nanoparticles, which were functionalized by coating with scale inhibitor molecules. The scale inhibitor DETPMP was used. In some implementations, scale inhibitors can also include ATMP, BHPMP, HDTMP, EDTMP, HEDP, PAPEMP, PBTC, or phosphate esters.TABLE 1Water composition of Wasia aquifer waterIonsNa+K+Ca2+Mg2+Sr2+HCO3−SO42−Cl−(mg / L)16001506101081228510703022

[0052] The absolute viscosity (in centipoise, cP) was measured at different spindle rotation speeds (rotations per minute, rpm), using a rotational viscometer (Brookfield LVDV-II CP). The torque on the rotating shaft of the spindle was used to measure the fluid's resistance to flow. Fluid temperature was controlled by a water jacket connected to a water bath. The test temperature was set at 151° F. (66° C.). The test temperature was selected to match a sandstone reservoir in the Central Arabian field.

[0053] A change in viscosity with time for different spindle rotation speeds are observed in FIG. 5. The viscosity decreased as a function of increasing time. In addition, as the spindle rotation speed increased, the magnitude of the viscosity of the nanofluid decreased. At a spindle rotation speed of 100 rpm, the viscosity reached a value of approximately 300 cP.

[0054] FIG. 6 is a graphical summary of the rheological behavior of the nanofluid described in FIG. 5. The measured viscosity values of the nanofluid that include the nanoparticles functionalized with a scale inhibitor is shown. The measured viscosity decreased with an increase in spindle rotation speed (shear force). At 15 rpm, the viscosity was measured to be 2225 cP. On doubling the rotation speed to 30 rpm, a significant reduction in viscosity was observed. The viscosity of the nanofluid was measured as 949 cP. The nanofluid viscosity was further reduced to 406 cP when the spindle rotation speed was 60 rpm. At a spindle rotation speed of 100 rpm the viscosity was measured as 294 cP. The spindle rotation speed corresponds to a shear rate or flow rate in the near-wellbore region. For example, a spindle rotation speed of 30-100 rpm corresponds to 15-50 cm / min of flowrate in the near-wellbore region.

[0055] FIG. 7 is a process flow diagram of injecting a nanofluid that includes a scale inhibitor for SIS treatment in a heterogeneous reservoir.

[0056] At block 702, a solvent is injected through a well into a heterogeneous reservoir matrix to pre-flush the reservoir matrix. In some implementations, the well includes a vertical well or a horizontal well. In some implementations, the well includes a long reach horizontal well. In some implementations, the well includes a production well. The well is drilled in a subterranean zone, which includes a reservoir matrix of interest. In some implementations, the reservoir matrix is heterogeneous in nature. The drilled well defines a wellbore. The wellbore has a casing along which open holes are formed. The open holes communicate with various production zones in the heterogeneous reservoir matrix. A pre-flush can be conducted to alter the heterogeneous reservoir matrix surface to increase scale inhibitor interactions with the heterogeneous reservoir matrix surface. The heterogeneous reservoir matrix has varying permeabilities, porosities, and rock compositions.

[0057] At block 704, a nanofluid is injected into the heterogeneous reservoir matrix through the well, using a bullhead pump. In some implementations, the nanofluid includes a nanoparticle and an aqueous solvent. The nanoparticles can be formed either by adsorption or a precipitation reaction. In some implementations, the nanoparticles include a metal oxide such as calcium oxide, iron oxide, or aluminum oxide loaded with scale inhibitor molecules. In some implementations, the nanoparticles are formed by a precipitation reaction between a scale inhibitor and a divalent cation, such as calcium. In some implementations, the nanoparticles include carbon nanotubes or graphene oxide (GO) loaded with scale inhibitor molecules. In some implementations, the nanoparticles include quantum dots scale inhibitors such as, carboxyl-modified carbon quantum dots (CCQDs). In some implementations, the scale inhibitors include phosphonates or phosphate esters. Examples of scale inhibitors include DETPMP, ATMP, BHPMP, HDTMP, EDTMP, HEDP, PAPEMP, or PBTC.

[0058] In some implementations, the aqueous solvent used in the nanofluid includes a composition similar to the formation brine composition or an aquifer water composition as found in the well. In some implementations, the aqueous solvent includes a synthetic produced water, where the composition of the synthetic produced water is similar to the produced water found in the heterogeneous reservoir matrix.

[0059] At block 706, the nanofluid is self-diverted from a high permeability zone to a low permeability zone in the heterogeneous reservoir matrix. The nanofluid is shear thinning and the heterogeneity in the reservoir matric causes a difference in the shear rates. The difference in the shear rates cause the shear thinning fluid to self-divert into the low permeability zone. In a heterogeneous reservoir matrix, a high permeability zone has a low shear rate and a low permeability zone has a high shear rate. The viscosity is high in the high permeability zone. The nanofluid blocks the high permeability zone and diverts the flow of nanofluid into the low permeability zone, where the viscosity of the nanofluid is low, due to the high shear rate.

[0060] At block 708, after the nanofluid is injected through a well into the heterogeneous reservoir matrix, the well is shut in for a time period. In some implementations, the shut in time period includes hours. In some implementations, the shut in time period is one or more days. In some implementations, the shut in time period is about 4-50 hours. In some implementations, the shut in period enhances the interactions between the reservoir matrix and the scale inhibitors in the nanofluid.

[0061] At block 710, the well resumes production of several fluids. The wells produce hydrocarbons such as oil and produced water. In some implementations, the wells produce large volumes of produced water. The scale inhibitor concentration is measured in the produced water. Initially, the scale inhibitor concentration is high during production after the shut in time period. Gradually, the scale inhibitor concentration falls down and reaches a MEC value. When the scale inhibitor concentration falls below the MEC value, the nanofluid that includes the scale inhibitor is reinjected through the well into the reservoir matrix.

[0062] An implementation described herein provides a method of treating inorganic scale in a well that is drilled in a heterogeneous reservoir matrix. A heterogeneous reservoir matrix has varying permeabilities. The varying permeabilities can cause a change in the shear rate as a fluid flows through it. In some implementations, a nanofluid that includes a nanoparticle functionalized with a scale inhibitor and an aqueous solvent is injected into the reservoir matrix. The nanofluid is shear thinning. In some implementations, the shear thinning behavior of the nanofluid causes a self-diversion of the nanofluid from the high permeability zone towards the low permeability zone.

[0063] In some implementations, the methods of the present disclosure include a scale inhibitor squeeze treatment method, which uses a bullhead pump. The nanofluid that includes the scale inhibitors is injected as a slug into the reservoir matrix through a well. The reservoir matrix interacts with the scale inhibitor molecules. As the production of the well continues, the scale inhibitor molecules from the nanofluid are released into the produced fluids. The scale inhibitor molecules can prevent the formation of inorganic scale, such as calcium carbonate along the well tubing and casing during production. The scale inhibitor molecules can further reduce or prevent scale formation in the surface facilities as the production continues.

[0064] The advantages of this technology include an increase in squeeze treatment performance and can extend the squeeze lifetime. Further, in some implementations, the use of nanofluids reduces operation cost, as it is easy to deploy. The treatment program can be modified as needed.

[0065] Other implementations are also within the scope of the following claims.Exemplary Embodiments1. A scale treatment method comprising:pre-flushing a heterogeneous reservoir matrix with an aqueous solvent, wherein the aqueous solvent is injected through a well;

[0067] injecting a nanofluid into the heterogeneous reservoir matrix through the well, wherein the nanofluid comprises:

[0068] a nanoparticle functionalized by loading with a scale inhibitor; and

[0069] an aquifer water;

[0070] self-diverting the nanofluid, by a shear thinning behavior of the nanofluid, from a high permeability zone to a low permeability zone of the heterogeneous reservoir matrix;

[0071] shutting in the well for a time period to enhance retention of the scale inhibitor in the nanofluid, by the heterogeneous reservoir matrix; and

[0072] resuming a production of a plurality of fluids through the well.2. The method of embodiment 1, wherein the nanoparticle comprises a metal oxide functionalized with a scale inhibitor.3. The method of embodiment 1 or 2, wherein the nanoparticle comprises a carbon nanotube or graphene oxide loaded with a scale inhibitor.4. The method of any of embodiments 1 to 3, wherein the nanoparticle comprises a scale inhibitor and a divalent cation.5. The method of any of embodiments 1 to 4, wherein the nanoparticle comprises a carboxyl-modified quantum dots (CCQDs).6. The method of any of embodiments 1 to 5, wherein the scale inhibitor comprises amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.7. The method of any of embodiments 1 to 6, wherein the shear thinning behavior of the nanofluid enhances the flow of the nanofluid into the low permeability zone.8. The method of any of embodiments 1 to 7, wherein the nanofluid in the low permeability zone comprises a low viscosity at a high shear rate.9. The method of any of embodiments 1 to 8, further comprising measuring a concentration of the scale inhibitor in the plurality of fluids from the well, wherein the scale inhibitor comprises a minimum effective concentration (MEC).10. The method of any of embodiments 1 to 9, wherein when the concentration of the scale inhibitor falls below the MEC, the nanofluid is reinjected into the well.11. The method of any of embodiments 1 to 10, wherein shutting in the well comprises the time periods of 4-50 hours.12. A method of scale inhibitor displacement in a heterogeneous reservoir comprising:

[0073] injecting a nanofluid into the heterogeneous reservoir through a well, wherein the nanofluid comprises a nanoparticle functionalized by loading with a scale inhibitor and an aqueous solvent;

[0074] self-diverting the nanofluid into the heterogeneous reservoir by a non-Newtonian characteristic, wherein the non-Newtonian characteristic comprises a shear thinning behavior of the nanofluid; and

[0075] producing, through the well, a produced water stream from the heterogeneous reservoir comprising the scale inhibitor.13. The method of embodiment 12, wherein the nanoparticle comprises a metal oxide functionalized with a scale inhibitor and the aqueous solvent comprises an aquifer water.14. The method of embodiment 12 or 13, wherein the scale inhibitor comprises amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.15. The method of any of embodiments 12 to 14, wherein the scale inhibitor comprises DETPMP or phosphate esters.16. The method of any of embodiments 12 to 15, wherein the nanofluid has a viscosity ranging between 100-2500 cP measured by a spindle ranging between 10-100 rpm.17. The method of any of embodiments 12 to 16, wherein the heterogeneous reservoir comprises a high permeability zone and a low permeability zone.18. The method of any of embodiments 12 to 17, wherein the shear thinning behavior of the nanofluid causes a flow of a high viscosity nanofluid in the high permeability zone and a low viscosity nanofluid in the low permeability zone, caused by a difference in a shear rate.19. A system of scale treatment comprising:

[0076] a heterogeneous well through which a shear thinning nanofluid is injected into a subterranean formation comprising a plurality of permeabilities, wherein the plurality of permeabilities causes a self-diversion of the shear thinning nanofluid into a low permeability zone; and

[0077] a bullhead pump, which is used to pump the shear thinning nanofluid into the heterogeneous well.20. The system of embodiment 19, wherein the shear thinning nanofluid comprises a metal oxide nanoparticle functionalized with a scale inhibitor and an aquifer water.

Claims

1. A scale treatment method comprising:pre-flushing a heterogeneous reservoir matrix with an aqueous solvent, wherein the aqueous solvent is injected through a well;injecting a shear thinning nanofluid into the heterogeneous reservoir matrix through the well, wherein the shear thinning nanofluid comprises:a nanoparticle functionalized by loading with a scale inhibitor; andan aquifer water;self-diverting the shear thinning nanofluid from a first zone comprising a first shear rate to a second zone comprising a second shear rate of the heterogeneous reservoir matrix, wherein the first zone has a permeability higher than the second zone, causing the scale inhibitor to reach the second zone;shutting in the well for a time period to enhance retention of the scale inhibitor by the second zone; andresuming a production of a produced water stream through the well, wherein the produced water stream comprises the scale inhibitor.

2. The method of claim 1, wherein the nanoparticle comprises a metal oxide functionalized with a scale inhibitor.

3. The method of claim 1, wherein the nanoparticle comprises a carbon nanotube or graphene oxide loaded with a scale inhibitor.

4. The method of claim 1, wherein the nanoparticle comprises a scale inhibitor and a divalent cation.

5. The method of claim 1, wherein the nanoparticle comprises a carboxyl-modified quantum dots (CCQDs).

6. The method of claim 1, wherein the scale inhibitor comprises amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.

7. The method of claim 1, wherein the shear thinning nanofluid exhibits a first viscosity in the first zone, wherein the first viscosity at least partially impedes the flow of the shear thinning nanofluid in the first zone and diverts the shear thinning nanofluid into the second zone, wherein the first viscosity is higher than the second viscosity.8.-10. (canceled)11. The method of claim 1, wherein shutting in the well comprises the time periods of 4-50 hours.

12. A method of scale inhibitor displacement in a heterogeneous reservoir comprising:injecting a shear thinning nanofluid into the heterogeneous reservoir through a well, wherein the shear thinning nanofluid comprises a nanoparticle functionalized by loading with a scale inhibitor and an aqueous solvent;self-diverting the shear thinning nanofluid into the heterogeneous reservoir from a first zone comprising a first permeability to a second zone comprising a second permeability, the first permeability is higher than the second permeability, wherein the self-diverting comprises:flowing the shear thinning nanofluid into the first zone, wherein the shear thinning nanofluid exhibits a first viscosity in the first zone, wherein the first viscosity at least partially impedes the flow of the shear thinning nanofluid in the first zone; anddiverting the shear thinning nanofluid from the first zone into the second zone, causing the scale inhibitor to reach the second zone, wherein the shear thinning nanofluid exhibits a second viscosity in the second zone, wherein the second viscosity is lower than the first viscosity;andproducing, through the well, a produced water stream from the heterogeneous reservoir comprising the scale inhibitor.

13. The method of claim 12, wherein the nanoparticle comprises a metal oxide functionalized with a scale inhibitor and the aqueous solvent comprises an aquifer water.

14. The method of claim 13, wherein the scale inhibitor comprises amino trimethylene phosphonate (ATMP), bishexamethylene triamine pentamethylene phosphonate (BHPMP), hexamethylenediamine tetramethylene phosphonate (HDTMP), diethylenetriamine pentamethylene phosphonate (DETPMP), ethylene diamine tetramethylene phosphonate (EDTMP), 1-hydroxyethylidene-1,1-diphosphonate (HEDP), polyamino polyether methylene phosphonate (PAPEMP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), or phosphate esters.

15. The method of claim 14, wherein the scale inhibitor comprises DETPMP or phosphate esters.

16. The method of claim 12, wherein the shear thinning nanofluid has a viscosity ranging between 100-2500 cP measured by a rotational viscometer.

17. (canceled)18. (canceled)19. A system of scale treatment comprising:a heterogeneous well through which a shear thinning nanofluid comprising a nanoparticle functionalized with a scale inhibitor is injected into a subterranean formation comprising a plurality of permeabilities, wherein the plurality of permeabilities causes a self-diversion of the shear thinning nanofluid from a first zone comprising a first permeability to a second zone comprising a second permeability, causing the scale inhibitor to reach the second zone, wherein the first permeability is higher than the second permeability; anda bullhead pump, which is used to pump the shear thinning nanofluid into the heterogeneous well.

20. The system of claim 19, wherein the shear thinning nanofluid comprises a metal oxide nanoparticle functionalized with a scale inhibitor and an aquifer water.

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