Thermally activated lost circulation control

Abstract

A method of controlling fluid loss includes forming a treatment fluid comprising a thermally activated material and supplying the treatment fluid into a wellbore at a first, lower temperature. The method also includes introducing the treatment fluid into the formation at a second, higher temperature. Thereafter, the treatment fluid with thermally activated material is allowed to form a plug in the formation.

Description

THERMALLY ACTIVATED LOST CIRCULATION CONTROLBACKGROUNDField

[0001] Embodiments of the present disclosure generally relate to methods and apparatus for treating lost circulation in a wellbore. More particularly, embodiments of the present disclosure relate to thermally activated compositions for treating lost circulation.Description of the Related Art

[0002] Lost circulation is one of the frequent challenges encountered during drilling operations. Lost circulation, which can be encountered during any stage of operations, occurs when drilling fluid pumped into a well returns partially or does not return to the surface. While some fluid loss is expected, fluid loss beyond acceptable norms is not desirable from a technical, an economical, or an environmental point of view. About 75% of the wells drilled per year encounter lost circulation problems to some extent.

[0003] Lost circulation is one of the substantial causes of drilling-related nonproductive time (NPT) and associated cost overruns. Thus, lost circulation contributes significantly to oil and gas and geothermal well construction costs. Lost circulation is a cost-inflating event that can also damage the reservoir and reduce the ultimate productivity of the well.

[0004] The oil and gas industry currently spends many billions of dollars annually fighting lost circulation. Conventional lost circulations methods include circulation of pills of lost circulation materials such as nut hulls and calcium carbonate, and squeezes of cement, have not eliminated the problem. Despite decades of research and development, there are still no high-reliability solutions available for lost circulation.

[0005] There is, therefore, a need for an improved method of mitigating lost circulation.SUMMARY

[0006] Embodiments of the present disclosure relate to the use of novel thermally activated lost circulation materials for lost circulation control. In some embodiments, the novel thermally activated lost circulation materials have the ability to plug a loss zone, such as fracture zones, formation fissures, and vugular zones.

[0007] In some embodiments, the lost circulation materials are activated via a thermal gradient between a lower temperature borehole and a higher temperature loss zone. The activated lost circulation materials are used to plug off the loss zone in an oil and gas well or a geothermal well. In some embodiments, the thermally activated materials can be adjusted to activate in accordance with the temperature profile of the formation.

[0008] In some embodiments, a method of controlling fluid loss includes forming a treatment fluid comprising a thermally activated material and supplying the treatment fluid into a wellbore at a first, lower temperature. The method also includes introducing the treatment fluid into the formation at a second, higher temperature. Thereafter, the treatment fluid with thermally activated material can form a plug in the formation.

[0009] In some embodiments, a composition for controlling fluid loss includes a treatment fluid for use downhole and a thermally activated material in an amount from 1 % v / v to 25% v / v of the treatment fluid. The thermally activated material is configured to facilitate the composition in forming a plug upon experiencing a temperature increase of at least 50°F.

[0010] In some embodiments, a method of controlling fluid loss includes forming a treatment fluid comprising a cementing fluid and a thermally activated material. The method also includes supplying the treatment fluid into a wellbore at a first, lower temperature. The method further includes introducing the treatment fluid into the formation at a second, higher temperature. Thereafter, the treatment fluid with thermally activated material can form a cement plug in the formation.BRIEF DESCRIPTION OF THE DRAWINGS

[0011] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and are therefore not to be considered limiting of its scope, may admit to other equally effective embodiments.

[0012] Figure 1 illustrates an exemplary method of controlling a fluid loss during a drilling operation, according to some embodiments.

[0013] Figure 2 illustrates a fracture plugging test setup.

[0014] Figure 3A illustrates the rheology profiles of fluid formulations with TAMs 1 and 2.

[0015] Figure 3B illustrates the rheology profiles of fluid formulations with TAMs 3 and 4.

[0016] Figure 4 illustrates the consistency profiles of fluid formulations containing geopolymers.

[0017] Figure 5A illustrates the compressive strength of TAMs 1 to 4.

[0018] Figure 5B illustrates the tensile strength of TAMs 1 to 4.

[0019] Figure 5C illustrates the compressive strength and Young’s modulus of TAMs 1 to 4.

[0020] Figure 6 shows the CT scans of sandstone samples circulated with fluid formulations containing TAMs 1 to 4.

[0021] Figure 7 illustrates an exemplary pyrophyllite rock sample for testing TAMs.

[0022] Figure 8 illustrates an exemplary triaxial equipment for measuring a TAM’s ability to withstand a pressure differential.

[0023] Figure 9 shows the pre- and post-plugging images of TAMs in 2000-micron fracture samples.

[0024] Figure 10 illustrates the differential pressure evaluation for TAM 1 in a 2000- micron fracture.

[0025] Figure 11 illustrates the differential pressure evaluation for TAM 2 in a 2000- micron fracture.

[0026] Figure 12 illustrates the differential pressure evaluation for TAM 3 in a 2000- micron fracture.

[0027] Figure 13 illustrates the differential pressure evaluation for TAM 4 in a 2000- micron fracture.

[0028] To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements disclosed in one embodiment may be beneficially utilized on other embodiments without specific recitation.DETAILED DESCRIPTION

[0029] Embodiments of the present disclosure relates to thermally activated materials that can be implemented for lost circulation control in oil and gas wells and geothermal wells. As disclosed herein, thermally activated materials (TAM) may also be referred to interchangeably as thermally activated lost circulation material (TALCM).

[0030] In some embodiments, during lost circulation incidents, a treatment fluid, such as a cement fluid, may include a thermally activated material and is supplied into a loss zone in geological formations, such as fractured carbonates. Because the temperature in the wellbore is cooler than the temperature in the formation, the treatment fluid experiences a temperature increase when the treatment fluid enters the loss zone in the formation. In response to the temperature increase, the treatment fluid containing the thermally activated material forms a plug to mitigate the fluid loss.

[0031] As used herein, “loss zone” refers to a portion of a subterranean formation into which fluids in a wellbore may be lost. In certain embodiments, loss zones may include voids, vugular zones, washouts, perforations, natural fractures, induced fractures, and any combination thereof.

[0032] As referred to herein, the term “treatment fluid” will be understood to mean any fluid that may be used in a downhole operation. Exemplary downhole operations include drilling, cementing, completion, and stimulation operations. Exemplarytreatment fluids include, inter alia, drilling fluids, cementing fluids, completion fluids, workover fluids, conformance fluids, acidizing fluids, fracturing fluids, and other treatment fluids suitable for use downhole.

[0033] The thermally activated lost circulation materials of the present disclosure may be used in a variety of operations and environments in which plugging a loss zone may be desired. In certain embodiments, the thermally activated materials may be applicable to operations related to hydrocarbon wells or geothermal wells. Exemplary operations includes drilling, cementing, fracturing, completions, and other suitable operations. In some embodiments, the thermally activated materials may be introduced into a subterranean formation via a wellbore penetrating at least a portion of a subterranean formation.

[0034] The methods and systems of the present disclosure provide treatment fluids that may include one or more thermally activated lost circulation materials. In certain embodiments, the thermally activated materials of the present disclosure include polymers showing inverse solubility with respect to temperature. Exemplary polymers include polyoxyalkylene glycols (PAGs) such a polyethylene glycols (PEGs), polypropylene glycols (PPGs), or mixtures thereof. In some embodiments, these thermally activated polymers may exhibit phase separation at elevated temperatures, with associated increase in viscosity. In some embodiments, the thermally activated materials of the present disclosure include salts showing inverse solubility with respect to temperature. Exemplary thermally activated salts include methylammonium lead halides such as CHsNHsPbh in y-butyrolactone, sodium citrate in water, or calcium citrate in water. In some embodiments, the thermally activated materials of the present disclosure include non-polar materials showing inverse solubility with respect to temperature. Exemplary thermally activated non-polar materials include chitin or chitosan in alkali solvents. In some embodiments, the thermally activated lost circulation materials can be a mixture of the polymers, salts, or non-polar materials.

[0035] In some embodiments, the thermally activated materials may be present in the treatment fluid in an amount from 1 % v / v to 25% v / v of the treatment fluid. For example, the thermally activated materials may be present in the treatment fluid in an amount from 2% v / v to 15% v / v or from 4% v / v to 11 % v / v of the treatment fluid. Insome examples, the thermally activated materials may be present in the treatment fluid in an amount of 5%, 6%, 7%, 8%, 9%, or 10% v / v of the treatment fluid.

[0036] In some embodiments, the thermally activated materials are configured to activate at a temperature above 100°F, above 150°F, above 200°F, above 250°F, or above 300°F. In some examples, the thermally activated materials are configured to activate at a temperature from 75°F to 500°F, from 100°F to 400°F, or from 120°F to 350°F. In some embodiments, the thermally activated materials are tuned to activate at a desired temperature by adjusting the amount of the thermally activated material in the treatment fluid, changing the type or mix of thermally activated material, or both.

[0037] In some embodiments, the thermally activated materials are configured to activate at a temperature that is at least 50°F above the bottom hole circulating temperature of the treatment fluid. In some examples, the activating temperature is at least 75°F, 90°F, or 100°F above the bottom hole circulating temperature of the treatment fluid. In some examples, the temperature difference between the bottom hole circulating temperature of the treatment fluid and the activating temperature is in a range from 75°F to 400°F or from 100°F to 350°F. In one or more of the embodiments described herein, the temperature of the formation is higher than the activation temperature.

[0038] The treatment fluids containing thermally activated materials of the present disclosure may be prepared using any suitable method or equipment. In some embodiments, the treatment fluids may be prepared at a well site or at an offsite location.

[0039] In some embodiments, the methods of the present disclosure may include introducing at least a portion of a treatment fluid containing a thermally activated material into a loss zone and allowing the treatment fluid to at least partially reduce losses within the loss zone. In some embodiments, the treatment fluid may reduce losses within the loss zone by experiencing a temperature change as a result of leaving the cooler wellbore and entering the warmer loss zone. In some embodiments, the treatment fluids of the present disclosure may reduce losses within the loss zone by allowing the treatment fluid to at least partially form a viscous plug or solid plug in the loss zone. Examples of the loss zone include voids, vugular zones, perforations, and natural or induced fractures. In some embodiments, one or more treatment fluidsmay at least partially plug a loss zone to mitigate further fluid losses. In some embodiments, the thermally activated materials are mixed with a treatment fluid and pumped down a wellbore to mitigate fluid loss. The treatment fluids containing thermally activated material may be used during or subsequent to drilling operations or prior to primary cementing operations to mitigate or prevent lost circulation.

[0040] In some embodiments, the thermally activated materials are added to a cementing fluid. For example, the PAGs can be added to the cementing fluid. In this case, the temperature-activated phase behavior of the PAGs generates a high viscosity that prevents further invasion of the cementing fluid into the loss zone. The cementing fluid eventually sets up as a hard plug. The thermally activated materials advantageously provides a delaying effect to the cementing fluid that can significantly increase the probability of success for the cementing fluid to close off the loss zone.

[0041] Figure 1 illustrates an exemplary system and method for mitigating fluid loss, according to some embodiments. In this embodiment, a treatment fluid 120 containing thermally activated materials is pumped downhole via a drill string 110. For example, the treatment fluid can be a cementing fluid. After exiting the drill bit 115, the treatment fluid 120 flows up the annulus between the drill string 110 and the wellbore 105. Some of the treatment fluid 120 enters into a loss zone in the formation, such as a vugular zone 101 or a large fracture zone 102. While circulating in the wellbore 105, the treatment fluid 120 is at a temperature that is cooler than the formation temperature. Upon entering the loss zones, the treatment fluid 120 experiences a temperature increase due to the higher temperature in the formation. The formation temperature near the wellbore is cooler than the formation temperature because of the effect of the cooler treatment fluid circulating in the wellbore. As the treatment fluid enters deeper into loss zones 101 , 102 (e.g., further away from the wellbore), the cooling influence of the wellbore diminishes and the effect of the higher formation temperature increases. Upon encountering the activation temperature, the thermally activated materials in the treatment fluid 120 form a viscous plug 130 (or solid plug) in the loss zones 101 , 102. The cement in the treatment fluid may cure to form a solid plug to close off the loss zones, thereby stopping or reducing fluid loss.

[0042] Examples

[0043] Cementitious Materials

[0044] The cementitious materials utilized as the base fluids to develop the treatment fluid formulations are Ordinary Portland Cement (OPC) and Class F Fly Ash (FA). The oxide compositions of these cementitious materials, expressed as mass percentages, are shown in Table 1. The OPC and FA were obtained from Texas Lehigh Cement Company and SEFA Group, respectively.Table 1 : Chemical composition of cementitious materials.

[0045] Thermally Activated Materials (TAM)

[0046] Four distinct types of TAMs were selected for these examples, as shown in Table 2. These TAMs belong to the categories of polymers, salts, and non-polar materials. For the OPC-based fluid formulations, which were prepared with a water- to-solid ratio of 0.385, TAMs were incorporated. For the FA-based fluid formulations, different alkaline activators were added to create geopolymers or alkali-activated materials, with a water-to-solid ratio of 0.35.Table 2: TAMs and their properties.

[0047] Rheology and Mechanical Properties

[0048] The rheological profiles of the fluid formulations are determined to assess the effectiveness of TAMs. For temperatures below 200°F, a rotational viscometer was employed to obtain these profiles. At temperatures exceeding 200°F, a High-Pressure High-Temperature (HPHT) Consistometer was used to evaluate the fluid consistency profile, which is related to the fluid’s rheology. Compressive and tensile strength tests were conducted to evaluate the mechanical behavior of TAMs once they enter fractures or vugs.

[0049] Rheology and Consistency

[0050] Rheological profiles as a function of temperature were obtained using a Couette coaxial cylinder rotational oilfield viscometer, following the guidelines of API RP 10B-2 (2010). The fluid was subjected to a constant shear rate of 150 rpm and the temperature was gradually increased from surface temperature (73°F) to 200°F.

[0051] Fluid consistency tests were performed using an HPHT Consistometer, where the temperature was gradually increased from 73°F to 350°F over 90 minutes. The pressure was initially set at 1 ,000 psi and progressively increased to 3,000 psi during this time period. The fluid was subjected to a constant shear rate of 150 rpm throughout the test. When the fluid achieves a Bearden consistency (Be) value of 70, it is considered non-displaceable, indicating its ability to mitigate further fluid losses.

[0052] Compressive and Tensile Strength

[0053] Three cylindrical samples (4 inches in length and 2 inches in diameter) of the fluid formulations were cured for one day and three days at the temperature expected in the fractures. Compressive strength was estimated using Equation 1 , following ASTM C39 / C39M (2021 ), with a ramp rate set at 48 psi / sec. Tensile strength was calculated using Equation 2, with a ramp rate set at 12 psi / sec, following ASTM C496 / C496M (2017).F represents the load at failure (Ibf), A is the cross-sectional area (in2), L is the length of the sample (in), and D is the diameter of the sample (in).

[0054] Fracture Plugging Tests and CT Scans

[0055] The fracture plugging tests were conducted using the setup illustrated in Figure 2. A cylindrical sandstone sample with a fracture size of 0.25 inches 1 0.63 cm was used. The sandstone sample was coupled to a heating jacket to provide the necessary heat. Sample treatment fluids were formed by incorporating the TAMs into the fluid formulations. The sample treatment fluids has an initial temperature of T1. The sandstone samples were heated to the target temperature (T2) and allowed to equilibrate for 30 minutes before initiating fluid circulation. The target temperature (T2) was selected based on the temperature (T2) that the fluid would encounter in a geothermal (GT) well fracture. The sample treatment fluids were circulated through the fracture in the pre-heated sandstone sample. A collector was placed beneath the sandstone sample to gather any passing fluid. If a significant amount of fluid was collected, then the formulation was considered ineffective for plugging the fractures. On the other hand, if only a minimal amount of fluid was collected, then the formulation was considered highly effective at sealing the fractures. The sandstone samples were then examined using CT scans to visualize the plugging behavior of the formulations.

[0056] Experimental Results and Discussion

[0057] During circulation, the treatment fluid, such as drilling mud or cement formulations, encounter the bottom hole circulating temperature (BHCT) in the wellbore. After entering loss zones (e.g., fractures or vugs), the treatment fluids quickly experience the bottom hole static temperature (BHST), which is higher than the BHCT due to the natural GT temperature gradient. This temperature contrast is leveraged to cause the TAMs to form plugs to help seal the loss zones in GT wells. When the TAMs are incorporated into the treatment fluids, the mixture remains in a liquid state in the near wellbore region, where the temperature is at or closer to the cooler BHCT. Upon entering the fractures or vugs where the BHST is higher than the BHCT, the mixture undergoes a phase change, becoming highly viscous or solid, effectively sealing the fractures. These temperature conditions between the BHCT and the BHST are beneficially used to select TAMs for different GT wells (or hydrocarbon wells).

[0058] TAMs 1 , 2, 3, and 4 were incorporated into the OPC fluid formulations and tested for viscosity as a function of temperature, as shown in Figures 3 and 4. The results were compared to the viscosity of the OPC fluid formulation (without TAMs), which is often the standard choice for cement squeeze operations in GT wells. Figure 3 shows the results for TAMs 1 and 2. Figure 4 shows the results for TAMs 3 and 4. As seen in the Figures, the viscosities of formulations with TAMs 1 , 2, 3, and 4 displayed a sharp increase at various temperatures known as trigger ( / .e., activation) temperatures. For example, 5% and 10 % by volume of TAM 1 ( / .e., PEG) were added to regular Portland cement. As shown in Figure 3, the 5% TAM 1 and the 10% TAM 1 demonstrated an increase in viscosity at around 184°F and 166°F, respectively. The flatlines occurring after the viscosity increase indicate the TAMs are effectively unpumpable at this and higher temperatures. In contrast, the viscosity of the OPC formulation remained steady without significant changes, and therefore not temperature dependent, highlighting why many cement squeeze jobs fail. The viscosity increases caused by TAMs upon entering fractures can be highly effective in mitigating fluid losses. By adjusting the concentration of TAMs in the fluid formulations, the trigger temperatures can be effectively modified, which is beneficial for developing solutions tailored to a variety of GT wells and oil and gas wells. These formulations are particularly suitable for shallow sections of GT wells and most oil and gas wells where the temperatures encountered are not extremely high.

[0059] In some embodiments, alkali activated materials such as geopolymers may be used to plug loss zones for GT wells. In particular, the geopolymers may be used to plug high temperature loss zones. Geopolymers provide high resistance to acid gases such as CO2 and H2S commonly encountered in high-temperature GT wells. Thus, geopolymers can be advantageously used for lost circulation control GT wells. In this example, FA was used as a cementitious material (aluminosilicate source), and different alkaline activators were utilized to create the geopolymer formulations. While FA is disclosed, other suitable precursor materials may be used with the alkaline activators. Suitable alkaline activators include potassium hydroxide, sodium hydroxide, potassium silicates, and the like. HPHT consistometer was used to evaluate the consistency of the formulation as a function of temperature, as shown in Figure 4. Two high-temperature plugging systems were developed, displaying triggertemperatures of 262°F and 362°F, respectively. The formulation is considered no longer pumpable once the consistency reaches a value of 70 Be. In this example, these fluid formulations become effectively non-pumpable or non-displaceable at temperatures exceeding 262°F and 362°F, making them highly suitable for deep GT wells.

[0060] Mechanical Properties

[0061] The compressive and tensile strength values of fluid formulations with TAMs 1 , 2, 3, and 4 are presented in Figures 5A, 5B, and 5C. Figures 5A and 5B show the compressive strength and tensile strength, respectively, of three day samples. These formulations were cured at 180°F for three days to estimate their strength. Figure 5C shows the compressive strength and the Young’s modulus of the samples after curing for one day. These results provide insight into the appropriate timing for resuming GT drilling operations to avoid further fluid losses after a cement squeeze job. The values in Figures 5A, 5B, and 5C demonstrate that the mechanical properties (e.g., compressive and tensile strengths) of the fluid formulations will be well-preserved, which ultimately helps in controlling fluid losses.

[0062] Fracture Plugging Test and CT Scans

[0063] The sandstone sample was pre-heated to the trigger temperatures indicated in Figures 3 and 4, after which the fluid formulations with TAMs were circulated through the borehole. When the OPC fluid formulation (conventional formulation used in GT wells) was circulated, 80% of the fluid was collected in the bottom collector. In contrast, for the OPC fluid formulations with TAMs 1 , 2, 3, and 4, no fluid was collected at the bottom. This indicates that the fluid completely plugged the borehole in the sandstone sample, demonstrating the thermal activation mechanism of TAMs 1 , 2, 3, and 4.

[0064] Following these tests, CT scans of the sandstone samples revealed that the borehole was predominantly plugged, with invasion depths illustrated in Figure 6. TAMs can be utilized for cement squeeze jobs to effectively seal fractures or vugs in different formations within GT wells.

[0065] Pyrophyllite Rock Samples

[0066] The average fracture size in geothermal wells is 2000 micron. The following tests were conducted to evaluate the behavior of TALCMs within the fracture, particularly their post-plugging performance in terms of the differential pressure they can withstand.

[0067] Step 1 : Inject TALCMs into the sample preheated to the transition temperature required for their activation.

[0068] Cylindrical pyrophyllite rock samples (3 inches in length and 1.5 inches in diameter) were selected to represent formations typically encountered in geothermal wells. The density and permeability of these samples are approximately 2.56 g / cc and 120 nano Darcy, respectively. A 0.5-inch borehole was drilled into the samples, followed by the creation of a fracture with the desired dimensions. The samples were then placed in a temperature-controlled oven to reach thermal equilibrium. TALCM formulations were prepared and flowed through the borehole (Figure 7), with the flow through the fracture being observed to determine whether the formulation effectively plugged the fracture.

[0069] TALCM formulations (OPC with 5% PEG, 5% PPG, 5% Liquid Chitosan, and 5% Sodium Citrate) were prepared and injected into samples with 2000-micron fracture sizes. The results are displayed in Table 3.Table 3: TALCMs: fracture plugging results.

[0070] Step 2: Load the samples with fractures filled with TALCMs into the triaxial equipment to measure the pressure differential (overbalance pressure) each material can withstand before additional fluid losses can occur.

[0071] Before loading the samples into the triaxial equipment, a sand pack was placed around the sample to simulate the formation and assess the fluid loss behavior from the borehole into the formation (Figure 8). Positive displacement pumps were used to control borehole injection pressure, confining pressure, and sand pack pressure, respectively. A confining pressure of 500 psi was applied to the sample by compressing the confining fluid (mineral oil) within the vessel for all tests. Additionally, the sample was vacuum -saturated from both the borehole and sand pack sides at 100 psi to remove air from the flow lines. After approximately one hour of system stabilization, with water as the borehole fluid, the borehole injection pressure was incrementally increased by 250 psi to evaluate the conductivity between the borehole and sand pack through the TALCM-filled fracture. The sand pack volume was continuously monitored throughout the test. A sudden rise in the sand pack pump flow rate indicates the presence of a conductive pathway within the fracture, accompanied by an increase in sand pack pressure. The differential pressure is measured as the difference between borehole pressure and sand pack pressure. The results for different TALCMs are presented below.

[0072] The samples with a 2000-micron fracture filled with TALCMs (OPC with 5% PEG, 5% PPG, 5% Liq Chitosan, and 5% Sodium Citrate) were loaded and tested. Figure 9 shows the pre- and post-plugging images of TALCMs in 2000-micron fracture samples. Figures 10, 11 , 12, and 13 illustrate that TALCMs in a 2000-micron fracture can withstand a significant pressure differential. This confirms that TALCMs can successfully seal 2000-micron fractures and prevent fluid losses into the formation. Table 4 provides a summary of the results.Table 4: TALCMs: differential pressure results.

[0073] Embodiments of the present disclosure provide thermally activated materials that can be mix with treatment fluids to address lost circulation challenges in GT wells and oil and gas wells. By leveraging the temperature contrast between the wellbore and loss zones, fluid formulations with TAMs can undergo a phase change to form a highly viscous or solid that effectively seals the fractures or vugs. Fluid formulations can be customized for different geological formations and GT gradients or depths. The compressive and tensile strengths of TAMs demonstrate their ability to maintain structural integrity within fractures or vugs. Fracture plugging tests and posttest CT scans also confirmed the effectiveness of TAMs in sealing fractures.

[0074] In addition to geothermal wells and oil and gas wells, it is contemplated that embodiments of the present disclosure may be implemented with other types of wells, such as carbon storage wells (CCS / CCUS); waste water injection and other injection (e.g. EOR) wells; hydrogen exploration and production wells; geotechnical wells; other underground storage wells (e.g., nuclear waste); and the like.

[0075] In some embodiments, a method of controlling fluid loss includes forming a treatment fluid comprising a thermally activated material and supplying the treatment fluid into a wellbore at a first, lower temperature. The method also includes introducing the treatment fluid into the formation at a second, higher temperature. Thereafter, the treatment fluid with thermally activated material can form a plug in the formation.

[0076] In some embodiments, a composition for controlling fluid loss includes a treatment fluid for use downhole and a thermally activated material in an amount from 1 % v / v to 25% v / v of the treatment fluid. The thermally activated material is configured to facilitate the composition in forming a plug upon experiencing a temperature increase of at least 50°F.

[0077] In some embodiments, a method of controlling fluid loss includes forming a treatment fluid comprising a cementing fluid and a thermally activated material. Themethod also includes supplying the treatment fluid into a wellbore at a first, lower temperature. The method further includes introducing the treatment fluid into the formation at a second, higher temperature. Thereafter, the treatment fluid with thermally activated material can form a cement plug in the formation.

[0078] In some embodiments, the thermally activated material comprises a polyoxyalkylene glycol having an inverse solubility property with respect to temperature.

[0079] In some embodiments, the thermally activated material comprises polyethylene glycol, polypropylene glycol, or combinations thereof.

[0080] In some embodiments, the thermally activated material comprises a thermally activatable salt having an inverse solubility property with respect to temperature.

[0081] In some embodiments, the thermally activated material comprises a methylammonium lead halide, sodium citrate, calcium citrate, or combinations thereof.

[0082] In some embodiments, the thermally activated material comprises a thermally activatable non-polar materials having an inverse solubility property with respect to temperature.

[0083] In some embodiments, the thermally activated material comprises chitin or chitosan in alkali solvents.

[0084] In some embodiments, the treatment fluid is one of drilling fluids, cementing fluids, and other treatment fluids suitable for use downhole.

[0085] In some embodiments, the thermally activated material comprises from 1 % v / v to 25% v / v of the treatment fluid.

[0086] In some embodiments, the thermally activated material comprises from 2% v / v to 15% v / v of the treatment fluid.

[0087] In some embodiments, the thermally activated material is configured to activate at a temperature above 150°F.

[0088] In some embodiments, the thermally activated material is configured to activate at a temperature from 100°F to 400°F.

[0089] In some embodiments, the thermally activated material is configured to activate at a temperature that is at least 50°F above a bottom hole circulating temperature of the treatment fluid.

[0090] In some embodiments, the thermally activated material increases a viscosity of the treatment fluid.

[0091] It will be appreciated by those skilled in the art that the preceding embodiments are exemplary and not limiting. It is intended that all modifications, permutations, enhancements, equivalents, and improvements thereto that are apparent to those skilled in the art upon a reading of the specification and a study of the drawings are included within the scope of the disclosure. It is therefore intended that the following appended claims may include all such modifications, permutations, enhancements, equivalents, and improvements. The present disclosure also contemplates that one or more aspects of the embodiments described herein may be substituted in for one or more of the other aspects described. The scope of the disclosure is determined by the claims that follow.

Claims

What is claimed is:1 . A method of controlling fluid loss, comprising: forming a treatment fluid comprising a thermally activated material; supplying the treatment fluid into a wellbore at a first, lower temperature; introducing the treatment fluid into the formation at a second, higher temperature; and allowing the treatment fluid with thermally activated material to form a plug in the formation.

2. The method of claim 1 , wherein the thermally activated material comprises a polyoxyalkylene glycol having an inverse solubility property with respect to temperature.

3. The method of claims 1 or 2, wherein the thermally activated material comprises polyethylene glycol, polypropylene glycol, or combinations thereof.

4. The method of any preceding, claim, wherein the thermally activated material comprises a thermally activatable salt having an inverse solubility property with respect to temperature.

5. The method of any preceding, wherein the thermally activated material comprises a methylammonium lead halide, sodium citrate, calcium citrate, or combinations thereof.

6. The method of any preceding, wherein the thermally activated material comprises a thermally activatable non-polar materials having an inverse solubility property with respect to temperature.

7. The method of any preceding, wherein the thermally activated material comprises chitin or chitosan in alkali solvents.

8. The method of any preceding, wherein treatment fluid is one of drilling fluids, cementing fluids, and other treatment fluids suitable for use downhole.

9. The method of any preceding, wherein the thermally activated material comprises from 1 % v / v to 25% v / v of the treatment fluid.

10. The method of any preceding, wherein the thermally activated material comprises from 2% v / v to 15% v / v of the treatment fluid.

11. The method of any preceding, wherein the thermally activated material is configured to activate at a temperature above 150°F.

12. The method of any preceding, wherein the thermally activated material is configured to activate at a temperature from 100°F to 400°F.

13. The method of any preceding, wherein the thermally activated material is configured to activate at a temperature that is at least 50°F above a bottom hole circulating temperature of the treatment fluid.

14. A method of controlling fluid loss, comprising: forming a treatment fluid comprising a cementing fluid and a thermally activated material; supplying the treatment fluid into a wellbore at a first, lower temperature; introducing the treatment fluid into the formation at a second, higher temperature; and allowing the treatment fluid with thermally activated material to form a cement plug in the formation.

15. The method of claim 14, wherein the thermally activated material comprises polyethylene glycol, polypropylene glycol, or combinations thereof.

16. The method of claim 14, wherein the thermally activated material comprisesa methylammonium lead halide, sodium citrate, calcium citrate, or combinations thereof.

17. The method of any of claims 14-16, wherein the thermally activated material comprises from 1 % v / v to 25% v / v of the treatment fluid.

18. The method of any of claims 14-17, wherein the thermally activated material is configured to activate at a temperature from 100°F to 400°F.

19. The method of any of claims 14-18, wherein the thermally activated material is configured to activate at a temperature that is at least 50°F above a bottom hole circulating temperature of the treatment fluid.

20. The method of any of claims 14-19, wherein the thermally activated material increases a viscosity of the treatment fluid.21 . A composition for controlling lost circulation, comprising: a treatment fluid for use downhole; and a thermally activated material in an amount from 1% v / v to 25% v / v of the treatment fluid, and wherein the thermally activated material is configured to facilitate the composition in forming a plug upon experiencing a temperature increase of at least 50°F.

22. The composition of claim 21 , wherein the thermally activated material comprises polyethylene glycol, polypropylene glycol, or combinations thereof.

23. The composition of claim 21 , wherein the thermally activated material comprises a methylammonium lead halide, sodium citrate, calcium citrate, or combinations thereof.

24. The composition of claim 21 , wherein the thermally activated material comprises chitin or chitosan in alkali solvents.

25. The composition of any of claims 21-24, wherein the thermally activated material increases a viscosity of the composition.

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