阅读说明：本技术 用于防止井眼处理液损失的化学封堵物 (Chemical plug for preventing loss of wellbore treatment fluid ) 是由 拉金德拉·阿伦库马·卡尔冈卡 韦克兰特·巴瓦尼珊卡·韦格尔 阿卜杜拉·萨利赫·侯赛因·阿勒-亚米 于 2018-04-25 设计创作，主要内容包括：堵漏材料包含水性胶体分散体和脂肪酸的混合物。水性胶体分散体包含二氧化硅纳米粒子并且具有至少8的pH。胶体分散体和脂肪酸的合并在堵漏材料的pH小于8并且堵漏材料的温度在5℃至300℃的范围内时引发堵漏材料的凝胶化。将在井眼的一部分或其中形成井眼的地下地层的一部分中的开口密封可以包括向井眼提供水性胶体分散体和脂肪酸,将胶体分散体和脂肪酸混合以得到堵漏材料,引发堵漏材料的凝胶化,和使在井眼中的堵漏材料凝固以得到凝结凝胶。(The lost circulation material comprises a mixture of an aqueous colloidal dispersion and a fatty acid. The aqueous colloidal dispersion comprises silica nanoparticles and has a pH of at least 8. The combination of the colloidal dispersion and the fatty acid induces gelation of the lost circulation material when the pH of the lost circulation material is less than 8 and the temperature of the lost circulation material is in the range of 5 ℃ to 300 ℃. Sealing an opening in a portion of a wellbore or a portion of a subterranean formation in which the wellbore is formed may include providing an aqueous colloidal dispersion and a fatty acid to the wellbore, mixing the colloidal dispersion and the fatty acid to obtain a lost circulation material, initiating gelation of the lost circulation material, and allowing the lost circulation material in the wellbore to solidify to obtain a coagulated gel.)

1. A lost circulation material comprising a mixture of:

an aqueous colloidal dispersion comprising silica nanoparticles and having a pH of at least 8; and

a fatty acid;

wherein the combination of the colloidal dispersion and the fatty acid initiates gelation of the lost circulation material when the pH of the lost circulation material is less than 8 and the temperature of the lost circulation material is in the range of 5 ℃ to 300 ℃.

2. The lost circulation material of claim 1, wherein the fatty acid comprises at least one of: hexanoic, heptanoic, octanoic, nonanoic, decanoic, undecanoic and dodecanoic acids.

3. The lost circulation material of claim 2, wherein the fatty acid is comprised of at least one of: hexanoic, heptanoic, octanoic, nonanoic, decanoic, undecanoic and dodecanoic acids.

4. A lost circulation material as defined in claim 1, wherein the fatty acid comprises at least one of hexanoic acid, heptanoic acid, and octanoic acid.

5. A lost circulation material as defined in claim 4, wherein the fatty acid is comprised of at least one of hexanoic acid, heptanoic acid, and octanoic acid.

6. The lost circulation material of claim 1, wherein the colloidal dispersion comprises at least one of a salt and a water miscible organic solvent.

7. The lost circulation material of claim 1, wherein the silica nanoparticles range in size from about 1nm to about 500 nm.

8. The lost circulation material of claim 1, wherein the concentration of silica nanoparticles in the colloidal dispersion ranges from about 10 weight percent to about 50 weight percent.

9. A lost circulation material as defined in claim 1, wherein the combination of the colloidal dispersion and the fatty acid initiates gelation of the lost circulation material when the pH of the lost circulation material is less than about 7.

10. A lost circulation material as defined in claim 1, wherein the aqueous colloidal dispersion has a pH of about 11 or less.

11. A lost circulation material as defined in claim 1, wherein the ratio of the fatty acid to the colloidal dispersion is in the range of 0.25% to 4% by volume.

12. A lost circulation material as defined in claim 1, wherein the pH of the lost circulation material is in the range of about 1 to about 6.

13. A lost circulation material as defined in claim 1, wherein lowering the pH of the lost circulation material accelerates the gelling of the lost circulation material.

14. A lost circulation material as defined in claim 1, wherein increasing the temperature of the lost circulation material accelerates the gelling of the lost circulation material.

15. A lost circulation material as defined in claim 1, wherein increasing the concentration of silica nanoparticles in the lost circulation material or the concentration of fatty acids in the lost circulation material accelerates gelation of the lost circulation material.

16. A lost circulation material as defined in claim 1, wherein gelation of the lost circulation material results in a coagulated gel in the form of a solid gel or a semi-solid gel.

17. A method of sealing an opening in a portion of a wellbore or a portion of a subterranean formation in which the wellbore is formed, the method comprising:

providing a colloidal dispersion comprising silica nanoparticles and having a pH of at least 8 to the wellbore;

providing a fatty acid to the wellbore;

mixing the colloidal dispersion and the fatty acid to obtain a lost circulation material having a pH of less than 8 and a temperature in the range of 5 ℃ to 300 ℃, thereby initiating gelation of the lost circulation material; and

solidifying the lost circulation material in the wellbore to obtain a coagulated gel, wherein the coagulated gel seals an opening in a portion of the wellbore or a portion of a subterranean formation in which the wellbore is formed.

18. The method of claim 17, further comprising simultaneously providing the colloidal dispersion and the fatty acid to the wellbore.

19. The method of claim 17, further comprising combining the colloidal dispersion and the fatty acid to obtain the lost circulation material prior to providing the colloidal dispersion and the fatty acid to the wellbore.

20. The method of claim 17, further comprising accelerating gelation of the lost circulation material in the wellbore by: increasing the temperature of the lost circulation material in the wellbore, decreasing the pH of the lost circulation material in the wellbore, or increasing the concentration of fatty acids in the lost circulation material.

Technical Field

This document relates to methods and compositions for controlling and preventing the loss of wellbore treatment fluids in a wellbore.

Background

Wellbore treatment fluids used in the drilling, completion or maintenance of a wellbore may be lost to the subterranean formation during circulation of the fluid in the wellbore. Some or all of the loss of wellbore treatment fluid from the wellbore may occur through depletion zones, zones of lower pressure, loss zones with naturally occurring fractures, weak zones with fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and the like. As a result, the maintenance provided by such fluids is more difficult or expensive to implement. Therefore, it would be advantageous to control and prevent the loss of wellbore treatment fluid in the wellbore.

SUMMARY

In a first general aspect, a lost-circulation material comprises a mixture of an aqueous colloidal dispersion and a fatty acid. The aqueous colloidal dispersion comprises silica nanoparticles and has a pH of at least 8. The combination of the colloidal dispersion and the fatty acid induces gelation of the lost circulation material when the pH of the lost circulation material is less than 8 and the temperature of the lost circulation material is in the range of 5 ℃ to 300 ℃.

In a second general aspect, sealing an opening in a portion of a wellbore or a portion of a subterranean formation in which the wellbore is formed includes providing a colloidal dispersion comprising silica nanoparticles and having a pH of at least 8 to the wellbore, providing a fatty acid to the wellbore, mixing the colloidal dispersion and the fatty acid to obtain a lost circulation material having a pH of less than 8 and a temperature in a range of 5 ℃ to 300 ℃, thereby initiating gelation of the lost circulation material, and solidifying the lost circulation material in the wellbore to obtain a coagulated gel. The setting gel seals an opening in a portion of the wellbore or a portion of a subterranean formation in which the wellbore is formed.

Implementations of the first and second general aspects may include one or more of the following features.

In some embodiments, the fatty acid comprises, consists of, or consists essentially of at least one of: hexanoic, heptanoic, octanoic, nonanoic, decanoic, undecanoic and dodecanoic acids. In certain embodiments, the fatty acid comprises, consists essentially of, or consists of at least one of hexanoic acid, heptanoic acid, and octanoic acid.

The colloidal dispersion may comprise at least one of a salt and a water miscible organic solvent.

In some embodiments, the silica nanoparticles have a size in the range of about 1nm to about 500 nm. In certain embodiments, the silica nanoparticles have a size in the range of about 1nm to about 100 nm.

In certain embodiments, the ratio of fatty acid to colloidal dispersion is in the range of 0.25% to 4% by volume.

The concentration of silica nanoparticles in the colloidal dispersion is typically in the range of about 10 wt.% to about 50 wt.%. In some embodiments, the pH of the aqueous colloidal dispersion is about 11 or less.

The combination of the colloidal dispersion and the fatty acid can initiate gelation of the lost circulation material when the pH of the lost circulation material is less than about 7. In some embodiments, the pH of the lost circulation material is in the range of about 1 to about 6.

Lowering the pH of the lost circulation material, raising the temperature of the lost circulation material, increasing the concentration of silica nanoparticles in the lost circulation material, increasing the concentration of fatty acids in the lost circulation material, or a combination thereof generally accelerates the gelling of the lost circulation material.

In some embodiments, gelation of the plugging material results in a coagulated gel in the form of a solid gel or a semi-solid gel. The setting gel may be in the form of a solid gel having the appearance of a crystalline solid. The length of time between initiation of gelation and formation of a coagulated gel is typically at least 0.5 hours. The coagulated gel is stable indefinitely at a temperature in the range of 5 ℃ to 200 ℃.

Implementations of the second general aspect may include one or more of the following features.

In some embodiments, a second general aspect includes providing a colloidal dispersion and a fatty acid to a wellbore simultaneously. In certain embodiments, a second general aspect includes combining the colloidal dispersion and the fatty acid to obtain a lost circulation material prior to providing the colloidal dispersion and the fatty acid to the wellbore. The gelling of lost circulation material in the wellbore may be accelerated by: increasing the temperature of the lost circulation material in the wellbore, decreasing the pH of the lost circulation material in the wellbore, or increasing the concentration of fatty acids in the lost circulation material.

The disclosed lost circulation materials are advantageously water-based and contain environmentally acceptable components. The silica nanoparticles are environmentally friendly and the fatty acids are biodegradable and environmentally acceptable. In addition, the gelation time of the disclosed lost circulation materials can be advantageously controlled by, for example, adjusting the concentration of fatty acids, achieving predictable and controllable pumping times over a range of minutes to hours at a given temperature. Thus, the lost circulation material remains pumpable for a sufficient length of time for placement, and forms a network structure that results in gelation over a predictable length of time. The coagulated gel, which behaves as a crystalline solid, advantageously remains homogeneous and in place under restricted conditions (such as cracks and pore spaces).

Brief Description of Drawings

FIG. 1 depicts an exemplary system for providing a wellbore treatment fluid to a wellbore in a subterranean formation.

FIG. 2 is a flow chart illustrating operations in an exemplary process for sealing an opening in a portion of a wellbore or a portion of a subterranean formation in which the wellbore is formed.

Detailed Description

FIG. 1 depicts an exemplary system 100 for delivering a wellbore treatment fluid to a wellbore 102 in a subterranean formation 104. Wellbore treatment fluid from source 106 is pumped by pump 108 through line 110 to wellhead 112 and into wellbore 102 via tubing 114. As indicated by the arrows, the wellbore treatment fluid may be circulated back up the wellbore 102 through the annular path between the wellbore and the tubing 114. The wellbore treatment fluid may be lost to the subterranean formation 104 through depleted zones (depleted zones), zones of lower pressure, lost circulation zones with naturally occurring fractures (lost circulation zones), weak zones with fracture gradients exceeded by the hydrostatic pressure of the wellbore treatment fluid, and the like.

In one example, the drilling fluid is circulated downhole through the drill pipe to a drill bit at the lower end of the well, outwardly through the drill bit into the wellbore, and then uphole back to the surface through an annular path between the drill pipe and the wellbore. The drilling fluid is used to lubricate the drill string, maintain hydrostatic pressure in the wellbore, and carry away rock cuttings from the wellbore. The drilling fluid may be lost to the formation, causing the circulation of fluid in the wellbore to be too low to allow further drilling of the wellbore.

To control or prevent loss of wellbore treatment fluid into the formation, Lost Circulation Material (LCM) may be provided to the wellbore by a system such as system 100 to reduce loss of wellbore treatment fluid used in drilling, completion or maintenance of the wellbore. LCM in pellet form may be provided to the wellbore to control or prevent drilling fluid loss using pumpable and condensable inorganic coagulant materials.

The LCM comprises a mixture of a colloidal dispersion containing metal oxide nanoparticles and an activator. The metal oxide nanoparticles may be silica nanoparticles. The activator is a fatty acid.

In some embodiments, the fatty acid comprises at least one C6-C12 fatty acid, consisting essentially of at least one C6-C12 fatty acid, or consisting of at least one C6-C12 fatty acid (i.e., at least one of hexanoic, heptanoic, octanoic, nonanoic, decanoic, undecanoic, and dodecanoic acids). In some embodiments, the fatty acid comprises at least one C6-C8 fatty acid, consisting essentially of at least one C6-C8 fatty acid, or consisting of at least one C6-C8 fatty acid (i.e., at least one of hexanoic, heptanoic, and octanoic acids). The silica nanoparticles are environmentally friendly and the fatty acids are biodegradable and environmentally acceptable. The fatty acid is liquid at room temperature. Fatty acids lower the pH of the colloidal dispersion and thus promote gelation. The ratio of fatty acid to colloidal dispersion is in the range of about 0.25% to about 4% by volume. Increasing the concentration of fatty acids in the LCM generally promotes faster gelation of the LCM.

The size of the silica nanoparticles in the colloidal dispersion is in the range of about 1nm to about 500nm or about 1nm to about 100 nm. Smaller silica nanoparticle sizes generally promote faster LCM gelation. The concentration of silica nanoparticles in the colloidal dispersion ranges from about 10 wt% to about 50 wt%. Higher silica nanoparticle concentrations generally promote faster LCM gelation. In some embodiments, the colloidal dispersion comprises a salt. Examples of suitable salts include, but are not limited to, sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, sodium formate, potassium formate, cesium formate, and mixtures thereof. In some embodiments, the colloidal dispersion comprises a water-miscible organic solvent. Examples of suitable water-miscible organic solvents include, but are not limited to, methanol, ethanol, propanol, butanol, ethyl acetate, dimethyl sulfoxide, dimethylformamide, acetone, and mixtures thereof. The pH of the colloidal dispersion is typically in the range of about 8 to about 11.

When the pH of the colloidal dispersion is at least 8, the colloidal dispersion generally remains in liquid form by virtue of the electrical repulsion between the charged particles that stabilizes the dispersion. Disrupting the charge balance of the colloidal dispersion may cause the silica nanoparticles to aggregate, resulting in the formation of a gel prior to combining the fatty acid with the colloidal dispersion. Disrupting the charge balance may include at least one of: removing water from the colloidal dispersion, changing the pH of the colloidal dispersion, adding a salt to the colloidal dispersion, and adding a water-miscible organic solvent to the dispersion. Examples of suitable salts include, but are not limited to, sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, sodium formate, potassium formate, cesium formate, and mixtures thereof. Examples of suitable water-miscible organic solvents include, but are not limited to, methanol, ethanol, propanol, butanol, ethyl acetate, dimethyl sulfoxide, dimethylformamide, acetone, and mixtures thereof.

The colloidal dispersion and fatty acid were combined to give LCM. LCM typically has a viscosity in the range of about 1cP to about 1000cP at a temperature of 20 ℃. The concentration of the colloidal dispersion, the fatty acid, or both, can be varied as desired for a particular application. In one example, increasing the viscosity of the LCM may facilitate placement and control of the LCM location, as well as provide viscous flow diversion (visco division) to cover longer intervals.

Combining the colloidal dispersion and the fatty acid reduces the pH of the colloidal dispersion from at least 8 to less than 8 or less than about 7. In some embodiments, lowering the pH of the colloidal dispersion from at least 8 to less than 8 or less than about 7 initiates gelation of the LCM when the temperature of the LCM is in the range of 5 ℃ to 300 ℃. In some embodiments, gelation is induced at least in part by the formation temperature and the increase in LCM temperature that occurs in the formation due to the formation temperature. Thus, gelation occurs in situ, sealing an opening in a portion of the wellbore, a portion of the subterranean formation, or both.

It is believed that gelation occurs at least in part due to the collision of silica nanoparticles aggregated into a long chain-like network to form a gel. The collisions of the silica nanoparticles are increased by a decrease in the pH of the colloidal dispersion, an increase in the temperature of the LCM, or both. It is believed that the collisions of the silica nanoparticles result in the formation of siloxane bonds (Si-O-Si) between the silica nanoparticles. The formation of siloxane bonds can be catalyzed by the presence of hydroxide ions. When aggregate formation is complete, gelation results in the formation of a coagulated gel, resulting in a uniform three-dimensional network of long, beaded strings of silica nanoparticles.

Gelation may occur during static aging of the LCM. In some embodiments, gelation of the LCM is accelerated by lowering the pH of the LCM. Generally, the more acidic the pH of the LCM, the faster gelation proceeds. In some embodiments, gelation of the LCM is accelerated by increasing the temperature of the LCM. The temperature of the LCM during gelation may be in the range of 5 ℃ to 300 ℃, 5 ℃ to 250 ℃, or 5 ℃ to 200 ℃. In some embodiments, gelation of the LCM is accelerated by increasing the concentration of fatty acids in the LCM. The LCM may be allowed to set in the wellbore for a length of time as gelation proceeds, which advantageously allows the LCM to remain pumpable at a given temperature for a sufficient and predictable length of time in the range of about 30 minutes to about 48 hours while forming a network structure.

Gelation by LCM results in a coagulated gel in the form of a solid gel or semi-solid gel. In some embodiments, the coagulating gel is in the form of a solid crystalline material. The length of time between initiation of gelation and formation of a coagulated gel depends, at least in part, on the pH of the LCM, the temperature of the LCM, the concentration of silica nanoparticles in the colloidal dispersion, and the ratio of fatty acid to silica nanoparticles. A coagulated gel is formed in an opening in a portion of a wellbore or a portion of a subterranean formation to seal the opening. In some embodiments, the opening is a formation interval. The openings may be in a restricted condition such as a depletion zone, a zone of lower pressure, a loss zone with naturally occurring fractures, a weak zone with a fracture gradient that is exceeded by the hydrostatic pressure of the drilling fluid, and the like. The coagulated gel remains as a semi-solid gel or a solid gel in the opening, thereby reducing loss of wellbore treatment fluid through the opening. In some embodiments, the coagulating gel is stable indefinitely at a temperature in the range of 5 ℃ to 200 ℃. In certain embodiments, the coagulated gel is stable at temperatures up to 260 ℃ for at least two days. No precipitation of the silica nanoparticles was observed during gel formation or at high temperature.

FIG. 2 is a flow chart illustrating operations in an exemplary process for sealing an opening in a portion of a wellbore or a portion of a subterranean formation in which the wellbore is formed. In 202, a colloidal dispersion comprising silica nanoparticles and having a pH of at least 8 as described herein is provided to a wellbore. In some cases, the pH of the colloidal dispersion is about 11 or less. At 204, a fatty acid as described herein is provided to the wellbore. In 206, the colloidal dispersion and fatty acid are mixed to obtain LCM having a pH of less than 8 and a temperature in the range of 5 ℃ to 300 ℃. Mixing the colloidal dispersion and the fatty acid initiates gelation of the LCM at least in part due to lowering the pH of the LCM, raising the temperature of the LCM, or both. At 208, the LCM is solidified in the wellbore to obtain a coagulated gel, thereby sealing an opening in a portion of the wellbore or a portion of a subterranean formation in which the wellbore is formed.

In some embodiments, the order of the operations in process 200 may be changed. In some embodiments, operations in process 200 may be omitted or added. For example, one embodiment includes simultaneously providing a colloidal dispersion and a fatty acid to a wellbore. Another embodiment includes combining the colloidal dispersion and the fatty acid to obtain a lost circulation material prior to providing the colloidal dispersion and the fatty acid to the wellbore. Other embodiments include accelerating the gelling of lost circulation material in the wellbore by: increasing the temperature of the lost circulation material in the wellbore, decreasing the pH of the lost circulation material in the wellbore, or increasing the concentration of fatty acids in the lost circulation material.

Examples

2mL of SABIC FATTY ACID C6-C8 (available from SABIC Chemicals) was mixed with 100mL of IDISIL SI 4545 (a basic, aqueous colloidal nanosilica dispersion available from Evonik Industries), and the dispersion was thoroughly mixed with a stirrer. The SABIC FATTY ACID C6-C8 fatty acids comprise a mixture of 35-45% hexanoic and 55-65% octanoic fatty acids. Table 1 lists the properties of IDISIL SI 4545.

TABLE 1 Properties of IDISIL SI 4545

Other suitable colloidal dispersions include cembin der 17 and cembin der 50 available from akzo nobel. The properties of cemblinder 17 and cemblinder 50 are listed in table 2.

TABLE 2 Properties of CEMBINDER 17 and CEMBINDER 50

The resulting LCM was then subjected to static aging at 120 ℃ for 16 hours. After static aging for 16 hours, gelation produced a coagulated gel. A coagulated gel is a solid gel having the appearance of a crystalline solid.

Definition of

In this document, the terms "a", "an" or "the" are used to include one or more than one unless the context clearly indicates otherwise. The term "or" is used to refer to a non-exclusive "or" unless otherwise indicated. The statement of "at least one of a and B" has the same meaning as "A, B or a and B". Also, it is to be understood that the phraseology or terminology employed in the present disclosure and not otherwise defined is for the purpose of description only and not of limitation. The use of any section headings is intended to aid in the reading of the document and should not be construed as limiting; information related to the chapter title may appear within or outside of that particular chapter.

The recitation of values by range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of "about 0.1% to about 5%" or "about 0.1% to 5%" should be interpreted to include not only about 0.1% to about 5%, but also include individual values (e.g., 1%, 2%, 3%, and 4%) and sub-ranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. Unless otherwise indicated, a statement of "about X to Y" has the same meaning as "about X to about Y". Likewise, unless otherwise indicated, a statement of "about X, Y or about Z" has the same meaning as "about X, about Y, or about Z". The term "about" may allow for some degree of variation in the value or range, for example, within 10%, within 5%, or within 1% of the stated value or range limit.

The term "fluid" refers to gases, liquids, gels, slurries with high solids content, and critical and supercritical materials.

The term "wellbore treatment fluid" refers to a fluid used to treat a particular wellbore or reservoir condition. Examples of wellbore treatment fluids include drilling fluids, stimulation fluids, cleanup-up fluids, fracturing fluids, spotting fluids, completion fluids, remedial treatment fluids, abandonment fluids, acidizing fluids, cementing fluids, packer fluids, and workover fluids.

The term "drilling fluid" refers to fluids used in downhole drilling operations, such as fluids used in downhole drilling operations during formation of a wellbore. The drilling fluid may be water-based or oil-based.

The term "stimulation fluid" refers to a fluid used downhole during stimulation activities (including perforation activities) of a well that can enhance the production of the well. In some examples, the stimulation fluid may include a fracturing fluid or an acidizing fluid.

The term "drainage fluid" refers to a fluid used downhole during a drainage activity of a well (e.g., any process used to remove material from a subterranean formation that impedes the flow of desired material). In one example, the drainage fluid may be an acidizing treatment used to remove material formed by one or more perforating treatments. In another example, a drainage fluid may be used to remove the filter cake.

The term "fracturing fluid" refers to a fluid used downhole during a fracturing operation.

The term "spotting fluid" refers to a fluid used downhole during a spotting operation and may be any fluid designed for localized treatment of a downhole region.

The term "completion fluid" refers to a fluid used downhole during the completion phase of a well, which includes a cementing composition.

The term "remedial treatment fluid" refers to fluids used downhole for remedial treatment of a well. Remedial treatments may include treatments designed to increase or maintain the productivity of the well, such as stimulation or drainage treatments.

The term "waste fluid" refers to a fluid used downhole during or prior to the abandonment phase of a well.

The term "acidizing fluid" refers to fluids used downhole during acidizing treatments. In one example, an acidizing fluid is used in a drainage operation to remove material that impedes the flow of desired material, such as material formed during a perforation operation. In some examples, an acidified liquid is used for lesion removal.

The term "cementing fluid" refers to a fluid used during a cementing operation of a well. For example, the cementing fluid may comprise an aqueous mixture comprising at least one of cement and cement kiln dust. In another example, the cementing fluid may include a curable resin material, such as a polymer in an at least partially uncured state.

The term "packer fluid" refers to the fluid in the annular region of the well between the tubing and the outer casing that may be placed above the packer. In various examples, the packer fluid may provide hydrostatic pressure to reduce the pressure differential across the sealing element, reduce the pressure differential across the wellbore and casing to prevent collapse, and protect the metal and elastomer from corrosion.

The term "workover fluid" refers to fluids used in well intervention operations involving invasive techniques such as wireline, coiled tubing, snubbing and completion.

The term "lost circulation" refers to the partial or complete loss of wellbore treatment fluid into the formation. In one example, lost circulation includes the loss of drilling fluid during drilling operations.

The term "lost circulation material" refers to a material that is provided to a wellbore to inhibit or prevent fluid flow between two locations (e.g., between portions of the wellbore, between portions of a subterranean formation, between a portion of the wellbore and a portion of a subterranean formation, or between a portion of the wellbore and a portion of a tubing string in the wellbore).

The term "pill" refers to a small volume of fluid, such as less than 200 barrels, placed or circulated in a wellbore for a variety of specific functions. In one example, the lost circulation pill is designed to seal a portion of a wellbore or a portion of a subterranean formation through which fluid is lost.

The term "subterranean formation" refers to any material below the surface of the earth, including below the surface of the seafloor. For example, a subterranean formation may be any portion of a wellbore and any portion of a subterranean oil or water producing formation or region that is in contact with a wellbore fluid. In some examples, the subterranean formation may be any subsurface region or any subsurface portion in fluid contact with which liquid or gaseous petroleum substances, water, or the like may be produced. For example, the subterranean formation may be at least one of: the zone requiring fracturing, the zone around the fracture or fracture, and the zone around the flow path or flow path, where the fracture or flow path may optionally be fluidly connected to a zone of the subsurface producing oil or water, either directly or through one or more fractures or flow paths.

Other embodiments

It is to be understood that while the embodiments have been described in conjunction with the detailed description thereof, the foregoing description is intended to illustrate and not limit the scope of the invention, which is defined by the scope of the appended claims. Other aspects, advantages, and modifications are within the scope of the following claims.