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WO2025184218A1 - Commande de perte de circulation thermiquement activée - Google Patents

Commande de perte de circulation thermiquement activée

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Publication number
WO2025184218A1
WO2025184218A1 PCT/US2025/017403 US2025017403W WO2025184218A1 WO 2025184218 A1 WO2025184218 A1 WO 2025184218A1 US 2025017403 W US2025017403 W US 2025017403W WO 2025184218 A1 WO2025184218 A1 WO 2025184218A1
Authority
WO
WIPO (PCT)
Prior art keywords
thermally activated
activated material
treatment fluid
temperature
fluid
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
PCT/US2025/017403
Other languages
English (en)
Inventor
Eric Van Oort
Veerabhadra S DENDULURI
Maria JUENGER
Munir Aldin
Akshay THOMBARE
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
University of Texas System
University of Texas at Austin
Original Assignee
University of Texas System
University of Texas at Austin
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by University of Texas System, University of Texas at Austin filed Critical University of Texas System
Publication of WO2025184218A1 publication Critical patent/WO2025184218A1/fr
Pending legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/003—Means for stopping loss of drilling fluid
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/138—Plastering the borehole wall; Injecting into the formation

Definitions

  • 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.
  • 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.
  • Lost circulation is one of the substantial causes of drilling-related nonproductive time (NPT) and associated cost overruns.
  • NPT drilling-related nonproductive time
  • 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.
  • Embodiments of the present disclosure relate to the use of novel thermally activated lost circulation materials for lost circulation control.
  • the novel thermally activated lost circulation materials have the ability to plug a loss zone, such as fracture zones, formation fissures, and vugular zones.
  • 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.
  • the thermally activated materials can be adjusted to activate in accordance with the temperature profile of the formation.
  • 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.
  • 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.
  • 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.
  • Figure 1 illustrates an exemplary method of controlling a fluid loss during a drilling operation, according to some embodiments.
  • Figure 2 illustrates a fracture plugging test setup.
  • Figure 3A illustrates the rheology profiles of fluid formulations with TAMs 1 and 2.
  • Figure 3B illustrates the rheology profiles of fluid formulations with TAMs 3 and 4.
  • Figure 4 illustrates the consistency profiles of fluid formulations containing geopolymers.
  • Figure 5A illustrates the compressive strength of TAMs 1 to 4.
  • Figure 5B illustrates the tensile strength of TAMs 1 to 4.
  • Figure 5C illustrates the compressive strength and Young’s modulus of TAMs 1 to 4.
  • Figure 6 shows the CT scans of sandstone samples circulated with fluid formulations containing TAMs 1 to 4.
  • Figure 7 illustrates an exemplary pyrophyllite rock sample for testing TAMs.
  • Figure 8 illustrates an exemplary triaxial equipment for measuring a TAM’s ability to withstand a pressure differential.
  • Figure 9 shows the pre- and post-plugging images of TAMs in 2000-micron fracture samples.
  • Figure 10 illustrates the differential pressure evaluation for TAM 1 in a 2000- micron fracture.
  • Figure 11 illustrates the differential pressure evaluation for TAM 2 in a 2000- micron fracture.
  • Figure 12 illustrates the differential pressure evaluation for TAM 3 in a 2000- micron fracture.
  • Figure 13 illustrates the differential pressure evaluation for TAM 4 in a 2000- micron fracture.
  • 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.
  • thermally activated materials TAM
  • TALCM thermally activated lost circulation material
  • a treatment fluid such as a cement fluid
  • a thermally activated material may be 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.
  • loss zone refers to a portion of a subterranean formation into which fluids in a wellbore may be lost.
  • loss zones may include voids, vugular zones, washouts, perforations, natural fractures, induced fractures, and any combination thereof.
  • 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.
  • exemplary treatment 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.
  • 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.
  • 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.
  • the thermally activated materials may be introduced into a subterranean formation via a wellbore penetrating at least a portion of a subterranean formation.
  • the methods and systems of the present disclosure provide treatment fluids that may include one or more thermally activated lost circulation materials.
  • 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.
  • PAGs polyoxyalkylene glycols
  • these thermally activated polymers may exhibit phase separation at elevated temperatures, with associated increase in viscosity.
  • the thermally activated materials of the present disclosure include salts showing inverse solubility with respect to temperature.
  • thermally activated salts include methylammonium lead halides such as CHsNHsPbh in y-butyrolactone, sodium citrate in water, or calcium citrate in water.
  • thermally activated materials of the present disclosure include non-polar materials showing inverse solubility with respect to temperature.
  • thermally activated non-polar materials include chitin or chitosan in alkali solvents.
  • the thermally activated lost circulation materials can be a mixture of the polymers, salts, or non-polar materials.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the activating temperature is at least 75°F, 90°F, or 100°F above the bottom hole circulating temperature of the treatment fluid.
  • 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.
  • the temperature of the formation is higher than the activation temperature.
  • the treatment fluids containing thermally activated materials of the present disclosure may be prepared using any suitable method or equipment.
  • the treatment fluids may be prepared at a well site or at an offsite location.
  • 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.
  • 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.
  • 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.
  • one or more treatment fluids may at least partially plug a loss zone to mitigate further fluid losses.
  • 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.
  • the thermally activated materials are added to a cementing fluid.
  • the PAGs can be added to the cementing fluid.
  • 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.
  • FIG 1 illustrates an exemplary system and method for mitigating fluid loss, according to some embodiments.
  • a treatment fluid 120 containing thermally activated materials is pumped downhole via a drill string 110.
  • the treatment fluid can be a cementing fluid.
  • 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.
  • the treatment fluid 120 While circulating in the wellbore 105, the treatment fluid 120 is at a temperature that is cooler than the formation temperature.
  • 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.
  • the cooling influence of the wellbore diminishes and the effect of the higher formation temperature increases.
  • 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.
  • cementitious Materials utilized as the base fluids to develop the treatment fluid formulations are Ordinary Portland Cement (OPC) and Class F Fly Ash (FA).
  • OPC Ordinary Portland Cement
  • FA Class F Fly Ash
  • Table 1 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.
  • TAM Thermally Activated Materials
  • TAMs Four distinct types 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.
  • 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.
  • Be Bearden consistency
  • F represents the load at failure (Ibf)
  • A is the cross-sectional area (in 2 )
  • L is the length of the sample (in)
  • D is the diameter of the sample (in).
  • 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.
  • the treatment fluid such as drilling mud or cement formulations
  • BHCT bottom hole circulating temperature
  • the treatment fluids 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.
  • BHST bottom hole static temperature
  • This temperature contrast is leveraged to cause the TAMs to form plugs to help seal the loss zones in GT wells.
  • 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.
  • 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.
  • the viscosities of formulations with TAMs 1 , 2, 3, and 4 displayed a sharp increase at various temperatures known as trigger (/.e., activation) temperatures.
  • trigger /.e., activation
  • 5% and 10 % by volume of TAM 1 were added to regular Portland cement.
  • 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.
  • 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.
  • 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.
  • alkali activated materials such as geopolymers may be used to plug loss zones for GT wells.
  • 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.
  • 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 trigger temperatures of 262°F and 362°F, respectively.
  • the formulation is considered no longer pumpable once the consistency reaches a value of 70 Be.
  • 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.
  • FIGS 5A, 5B, and 5C 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.
  • 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.
  • the OPC fluid formulation conventional formulation used in GT wells
  • 80% of the fluid was collected in the bottom collector.
  • 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.
  • TAMs can be utilized for cement squeeze jobs to effectively seal fractures or vugs in different formations within GT wells.
  • Step 1 Inject TALCMs into the sample preheated to the transition temperature required for their activation.
  • 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.
  • TALCM formulations OPC with 5% PEG, 5% PPG, 5% Liquid Chitosan, and 5% Sodium Citrate
  • 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.
  • 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.
  • the sample was vacuum -saturated from both the borehole and sand pack sides at 100 psi to remove air from the flow lines.
  • 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.
  • 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.
  • 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.
  • CCS/CCUS carbon storage wells
  • EOR waste water injection and other injection
  • hydrogen exploration and production wells e.g., geotechnical wells
  • other underground storage wells e.g., nuclear waste
  • 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.
  • 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.
  • 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.
  • the thermally activated material comprises a polyoxyalkylene glycol having an inverse solubility property with respect to temperature.
  • the thermally activated material comprises polyethylene glycol, polypropylene glycol, or combinations thereof.
  • the thermally activated material comprises a thermally activatable salt having an inverse solubility property with respect to temperature.
  • the thermally activated material comprises a methylammonium lead halide, sodium citrate, calcium citrate, or combinations thereof.
  • the thermally activated material comprises a thermally activatable non-polar materials having an inverse solubility property with respect to temperature.
  • the thermally activated material comprises chitin or chitosan in alkali solvents.
  • the treatment fluid is one of drilling fluids, cementing fluids, and other treatment fluids suitable for use downhole.
  • the thermally activated material comprises from 1 % v/v to 25% v/v of the treatment fluid.
  • the thermally activated material comprises from 2% v/v to 15% v/v of the treatment fluid.
  • 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.
  • 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.
  • the thermally activated material increases a viscosity of the treatment fluid.

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Abstract

L'invention concerne un procédé de commande de perte de fluide qui consiste à former un fluide de traitement comprenant un matériau thermiquement activé et alimenter, avec le fluide de traitement, un puits de forage à une première température plus basse. Le procédé consiste également à introduire le fluide de traitement dans la formation à une seconde température plus élevée. Ensuite, le fluide de traitement ayant le matériau thermiquement activé est autorisé à former un bouchon dans la formation.
PCT/US2025/017403 2024-02-26 2025-02-26 Commande de perte de circulation thermiquement activée Pending WO2025184218A1 (fr)

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US63/557,845 2024-02-26

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Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110071057A1 (en) * 2009-09-22 2011-03-24 Board Of Regents, The University Of Texas System Method of manufacture and use of large hydrophobe ether sulfate surfactants in enhanced oil recovery (eor) applications
US20150114646A1 (en) * 2012-04-09 2015-04-30 M-I L.L.C. Triggered heating of wellbore fluids by carbon nanomaterials
US20160265306A1 (en) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Cement isolation fluids for wellbores, methods of making, and methods of use
US20170240790A1 (en) * 2015-10-21 2017-08-24 Baker Hughes Incorporated Rare earth-containing compounds to enhance performance of downhole treatment compositions
US20200362222A1 (en) * 2018-09-07 2020-11-19 Halliburton Energy Services, Inc. Accelerating Agents For Resin Cement Composite Systems For Oil Well Cementing
US20240003222A1 (en) * 2020-11-13 2024-01-04 Schlumberger Technology Corporation Methods for shortening waiting-on-cement time in a subterranean well

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110071057A1 (en) * 2009-09-22 2011-03-24 Board Of Regents, The University Of Texas System Method of manufacture and use of large hydrophobe ether sulfate surfactants in enhanced oil recovery (eor) applications
US20150114646A1 (en) * 2012-04-09 2015-04-30 M-I L.L.C. Triggered heating of wellbore fluids by carbon nanomaterials
US20160265306A1 (en) * 2015-03-10 2016-09-15 Baker Hughes Incorporated Cement isolation fluids for wellbores, methods of making, and methods of use
US20170240790A1 (en) * 2015-10-21 2017-08-24 Baker Hughes Incorporated Rare earth-containing compounds to enhance performance of downhole treatment compositions
US20200362222A1 (en) * 2018-09-07 2020-11-19 Halliburton Energy Services, Inc. Accelerating Agents For Resin Cement Composite Systems For Oil Well Cementing
US20240003222A1 (en) * 2020-11-13 2024-01-04 Schlumberger Technology Corporation Methods for shortening waiting-on-cement time in a subterranean well

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