WO2025034820A1

WO2025034820A1 - Lost circulation control treatment

Info

Publication number: WO2025034820A1
Application number: PCT/US2024/041231
Authority: WO
Inventors: Surya Kiran PALLAPOTHU; Bipin Jain; Zakia NEDIR MAKHLOUF
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Priority date: 2023-08-07
Filing date: 2024-08-07
Publication date: 2025-02-13
Anticipated expiration: 2026-02-07

Abstract

Methods for reducing fluid loss in subterranean wells are presented herein. The methods generally include contacting a brine with an alkali metal silicate within a subterranean formation, and applying a sealant to the formation. In one method, a brine solution is pumped into a well, an alkali metal silicate solution is pumped into the well in contact with the brine solution, a sealant is pumped into the well after the alkali metal silicate solution to restrict flow pathways within the formation, and the sealant is displaced from the well into the formation. The brine is allowed to react with the alkali metal silicate to precipitate solids that enhance the sealing performance of the sealant and further restrict the flow pathways within the formation

Description

LOST CIRCULATION CONTROL TREATMENT

CROSS REFERENCE PARAGRAPH

[0001] This application claims the benefit of U.S. Provisional Application No. 63/518,051 , entitled "LOST CIRCULATION CONTROL TREATMENT," filed August 07, 2023, the disclosure of which is hereby incorporated herein by reference.

FIELD

[0002] This application for patent relates to well treatment methods. More particularly the invention relates to the use of reactive materials to control loss of circulation fluid in wells.

BACKGROUND

[0003] During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through the wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.

[0004] Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively. When the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.

[0005] Wellbore fluids are circulated downhole to remove rock, and may deliver agents to combat the variety of issues described above. Fluid compositions may be water- or oil-based and may comprise weighting agents, surfactants, proppants, viscosifiers, fluid loss additives, and polymers. However, for a wellbore fluid to perform all of its functions and allow wellbore operations to continue, the fluid must stay in the borehole. Frequently, undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation. For example, wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole.

[0006] Lost circulation is a recurring drilling problem, characterized by loss of drilling mud into downhole formations. However, in addition to drilling fluids, lost circulation may remain an issue for other wellbore fluids such as including completion, drill-in, production fluid, etc. Fluid loss can occur naturally in earthen formations that are fractured, highly permeable, porous, cavernous, or vugular. These earth formations can include shale, sands, gravel, shell beds, reef deposits, limestone, dolomite, and chalk, among others.

[0007] Lost circulation may result from induced pressure during drilling or natural fractures within the formation rock. Specifically, induced mud losses may occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure weakens hydrocarbon- bearing rocks, but neighboring or inter-bedded low permeability rocks, such as shales, maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the mud weight required to support the shale exceeds the fracture resistance of nearby zones composed of weakly consolidated sands and silts. Another unintentional method by which lost circulation can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove such solids, the fluid density can increase, thereby increasing the hole pressure, and if such hole pressure exceeds the formation fracture pressure, fractures and fluid loss can result. In the case of losses due to natural fractures especially within the carbonate formations, drilling fluid is lost to the fractures as soon as drilling is initiated in fractured formation. The size of fractures and the interconnection of the fractures determine the loss rate of the drilling fluid.

[0008] Various methods have been used to restore circulation of a drilling fluid when a lost circulation event has occurred, particularly the use of lost circulation material (LCM) to seal or block further loss of circulation. These materials may generally be classified into several categories: surface plugging, interstitial bridging, and/or combinations thereof. In addition to traditional LCM pills, polymers that crosslink or absorb fluids and cement or gunk squeezes have also been employed.

[0009] Accordingly, there exists a continuing need for developments for new LCM treatments that may be used during a lost circulation event so that circulation may be more readily resumed.

SUMMARY

[0010] Embodiments described herein provide a method, comprising pumping a brine solution into a well; pumping a fluid containing an alkali metal silicate into the well to contact the brine solution; pumping a sealant into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation. [0011] Other embodiments described herein provide a method, comprising pumping a brine solution into a well; pumping a fluid containing a sodium silicate, a potassium silicate, or both, into the well; pumping a sealant into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation

[0012] Other embodiments described herein provide a method, comprising pumping a fluid containing a sodium silicate, a potassium silicate, or both, into the well; pumping a sealant comprising a brine solution, fibers, and particles into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation.

DETAILED DESCRIPTION

[0013] In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it may be understood by those skilled in the art that the methods of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

[0014] At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation — specific decisions are made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary of the disclosure and this detailed description, each numerical value should be read once as modified by the term "about" (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. The term “about” should be understood as any amount or range within 10% of the recited amount or range (for example, a range from about 1 to about 10 encompasses a range from 0.9 to 11). Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each possible number along the continuum between about 1 and about 10. Furthermore, one or more of the data points in the present examples may be combined together, or may be combined with one of the data points in the specification to create a range, and thus include each possible value or number within this range. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to a few specific data points, it is to be understood that inventors appreciate and understand that any data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and the points within the range.

[0015] Regarding chemical formulas, it should be noted that measurements may not conform precisely to the chemical formulas described herein due to various sources of error that can affect real-world testing. The chemical formulas described herein should therefore be understood as expressing the nominal chemical makeup of compounds, where real-world testing may show close, but not exact, conformity to the formulas.

[0016] As used herein, “embodiments” refers to non-limiting examples disclosed herein, whether claimed or not, which may be employed or present alone or in any combination or permutation with one or more other embodiments. Each embodiment disclosed herein should be regarded both as an added feature to be used with one or more other embodiments, as well as an alternative to be used separately or in lieu of one or more other embodiments. It should be understood that no limitation of the scope of the claimed subject matter is thereby intended, any alterations and further modifications in the illustrated embodiments, and any further applications of the principles of the application as illustrated therein as would normally occur to one skilled in the art to which the disclosure relates are contemplated herein. [0017] Methods are described herein for treating wells to recover capacity to circulate fluids within wells after a circulation loss event. These methods extend the function of conventional measures by adding to the plugging capability of measures such as the Losseal products available from SLB of Houston, Texas. The methods herein utilize a reaction between an alkali metal silicate and a brine solution to precipitate solids within a formation to add to plugging performance of the conventional sealants. Generally, the methods herein use an alkali metal silicate to react with cations in a brine to form solids that enhance the plugging function of a sealant. The result is that flow pathways can be plugged that are larger than those that can typically be plugged using the sealant alone. The brine can be pumped as a mixture with the alkali metal silicate, depending on reactivity of the silicate with the brine, or the brine can be used as a base for the sealant, or the brine can be pumped separately from the alkali metal silicate and the sealant material. To further enhance performance of the system, a cementitious material can also be used with the sealant and the brine/silicate reaction product.

[0018] The alkali metal silicate can be sodium or potassium silicate in most cases. Sodium silicate is highly reactive with brines, and potassium silicate is mildly reactive with brines. Either material will react with cations in the brine to form a solid precipitate that can plug flow paths. Other alkali metal silicates can also be used, instead of or in mixture with sodium and/or potassium silicates. The silicates referred to herein can be metasilicates, orthosilicates, and/or pyrosilicates. The brine can be a solution of a mono-, di-, or tri-valent salt, or a combination thereof. Sodium and calcium chlorides and bromides are examples of salts that can be used as part of the brine.

[0019] A sealant, such as a Losseal Max product available from SLB of Houston, Texas, is used for the methods herein. The Losseal Mas system of SLB typically uses fibers and particles dispersed in a fluid medium that has a target viscosity, and optionally density, to maintain dispersion of the solid materials in the fluid medium. The fluid medium, in this case, can be brine or salt water, such as seawater, or a type of fresh water, including distilled water. The solid materials in the Losseal Max system are typically FAB and FAB AS materials, which include fine particles and fibrous materials having particle size of 1 to 500 pm, such as 1 to 200 pm. The fibers can be natural or synthetic fibers that have length of 1 to 10 mm, such as 2 to 8 mm. The fibers can be polymeric fibers such as nylon, polyvinyl alcohol, polyolefin, polyester, polylactic acid, polyamide, or a glass material such as borosilicate glass. The glass fibers can be silica-based materials that can contain oxides of calcium, boron, sodium, aluminum, iron, metal fiber, carbon fiber, or a combination thereof. Natural fibers that can be used include wool, plant fibers such as cotton, jute, or wood, and mineral fibers such as Wolasstonite. Other synthetic, semi-synthetic, modified natural, or regenerated fibers that can be used include rayon, artificial silk, Modal, Lycocell, and cellulose acetate.

[0020] The sealants described above, or a similar sealant designed to plug small flow pathways, are used with a system of brine and alkali metal silicate to enhance the performance of the sealant. Enhanced performance can be useful where subterranean formations can have flow pathways that exceed the nominal capacity of the sealant alone. For example, a sealant may have the capability to seal flow pathways up to about 10 mm alone, but used with the methods herein that capacity may be increased to 18-22 mm or more. These materials enable a method of treating a formation exhibiting well fluid loss by pumping a brine solution into the well, pumping a fluid containing an alkali metal silicate into the well to contact the brine solution, pumping a sealant into the well, displacing the sealant from the well into a formation adjacent to the well, and reacting the alkali metal silicate with the brine to close flow pathways within the formation. [0021] When used in a well having conventional well control equipment such as casings, chokes, and annulus valves, the materials used herein are pumped down the well through a pipe installed in the well. The pipe is placed within the well such that the bottom of the pipe is adjacent to the top of the zone where fluid loss was detected within the well. While pumping the materials down the well, flow within the annular space between the pipe and the well wall or casing is closed using the annulus valve so the materials will not flow toward the surface but will flow from the bottom of the pipe into the formation around the well. Thus, while annulus flow is stopped, the brine solution is pumped into the well, then the alkali metal silicate solution is pumped into the well to contact the brine solution, then the sealant is pumped into the well. Spacer materials can optionally be pumped into the well between the brine solution and the alkali metal silicate solution and/or between the alkali metal silicate solution and the sealant. The sealant is pumped until enough sealant has flowed into the well to displace a portion of the sealant from the bottom of the well into the formation, or the sealant can be displaced into the formation using a displacement material such as drilling mud. A spacer, which is a water material (water or brine), and which can be densified and/or viscosified to any useful extent to form a stabilized suspension, can be pumped between the fluid containing the alkali metal silicate and the sealant. For example, the sealant can be displaced using 10 bbl of a drilling mud or using 10 bbl extra sealant, beyond the pipe fill volume. Spacers used herein can also be densified and/or viscosified to any convenient extent. The spacers used herein can also be, or contain, brine, which can be a dilute brine not intended to react in the sealant system or concentrated brine intended to react, or contribute to reaction, in the sealant system

[0022] The methods herein rely on a reaction between the alkali metal silicate and the brine to precipitate large amounts of nanoparticles can agglomerate together, and that interact with the materials of the sealant to enhance plugging of flow pathways. In order to form a large precipitate mass, high concentration brine solutions and alkali metal silicate solutions can be used. These solutions can be nearly saturated, saturated, supersaturated, or saturated slurries. Thus, in one example the alkali metal silicate is a solution of 50% sodium silicate in water. In other cases, the alkali metal solution can be a saturated solution that also includes alkali metal silicate solids. The brine solution, likewise, can be a strong brine solution, saturated brine solution, or saturated brine solution with salt solids. Where the solutions include undissolved solids, suspension aids such as densifiers and viscosifiers can be used to maintain the solids in suspension. Densifiers and viscosifiers commonly used in well treatment materials can be used for these purposes. Materials that can be used as the alkali metal silicate solution include D075, a sodium silicate solution available from SLB, and D079, which is a solid sodium silicate available from SLB, and which is dissolved and/or dispersed in a water, or aqueous, base fluid to form a sodium silicate solution or slurry. D079 can also be added to D075 to form an enhanced sodium silicate solution or a sodium silicate slurry.

[0023] The combination of brine solution and alkali metal silicate solution used in the methods herein can be used in a volume that is comparable to the volume of sealant used to treat a formation. Thus, for example, where a sealant such as Losseal is used in a pill of 50-100 bbl, the amount of combined brine solution and alkali metal silicate solution can be 20-40 bbl. More or less of each can be used, with varying effects on fluid loss. The combination of brine and silicate is useful in the methods herein because the reaction of brine with silicate causes severe precipitation of solids, so that highly loaded solutions can provide substantial plugging material to the system. [0024] In another method, the sealant can be prepared using a brine solution as a base fluid. In such cases, pumping a brine solution separately into the well can be avoided. In such methods, an alkali metal silicate solution is pumped into the well followed by the brine-based sealant. In such cases, the sealant will be loaded with salt in any amount up to a handling limit of the sealant. For example, salt loading of the sealant may reach a level at which the sealant is difficult to handle or pump into the well. The sealant is typically heavily loaded with salt but not beyond a handling limit. As above, the sealant is displaced into the formation from the bottom of the pipe. The brine in the sealant comes into contact with the alkali metal silicate within the formation resulting in precipitation of solids within the formation that interact with the materials of the sealant to enhance the plugging effectiveness of the sealant.

[0025] A spacer can optionally be pumped between the fluid containing alkali metal silicate and the brine-based sealant to separate the brine from the silicates so that reaction between the brine and the silicate is delayed until the components are deployed within the formation. Such spacers can be useful where the brine and silicate are highly reactive to prevent substantial reaction within the well before the components are able to enter the formation as liquids.

[0026] After the sealant is displaced into the formation, all well flow controls are closed to trap fluids within the well for a soak duration to allow reaction between the brine and the silicate solution to proceed. Depending on the reactivity and concentration of the components, the soak duration may be 2 hours or more. Additional pressure can be applied to the formation, after displacement of the sealant, to flow components of the sealing system into the formation. Reaction between the brine and the silicate can thus occur within the flow pathways of the formation to deposit solids in the flow pathways and plug, or reduce fluid conductivity of, the flow pathways. [0027] A composition of the brine solution, the fluid containing alkali metal silicate, or both, can be selected based on time to place the brine solution, the fluid containing alkali metal silicate, or both, within the formation. Concentration of salt in the brine and or alkali metal silicate in the fluid can be decreased to slow reaction time such that the fluids can be placed in a more distant formation, or increase to speed reaction time if the formation is close and long pumping is not required. Likewise, type or mixture of salt in the brine solution or alkali metal silicate in the fluid can be selected for fast or slow reaction speed based on time to place the materials within the formation. Such methods can be used to prevent excessive reaction before the fluids are placed within the formation such that the reaction can take place mainly after the fluids arrive at the target location within the formation.

[0028] In some cases, systems of different reactivity can be placed at different locations within the same well. For example, where a first location of a formation at a first depth is to receive a first fluid loss control treatment, and a second location of the formation at a second depth is to receive a second fluid loss control treatment, the brine/silicate system reactivity can be selected for the two different locations of the formation based on pumping time to place the two systems at the two locations of the formation. Thus, where the first location has a higher pumping time that the second location, the first fluid loss control treatment can use a brine and/or a fluid containing an alkali metal silicate to provide a first reactivity and the second fluid loss control treatment can use a brine and/or a fluid containing an alkali metal silicate to provide a second reactivity that is higher than the first reactivity. The relationship of the second reactivity to the first reactivity can be based on a relationship of the second pumping time to the first pumping time. For example, a ratio of the second reactivity to the first reactivity can be the same as a ratio of the second pumping time to the first pumping time. In other cases, the relationship of the second reactivity to the first reactivity can be based on a relationship between a temperature at the second location and a temperature at the first location. For example, where the temperature at the second location is higher than the temperature at the first location, the second reactivity can be selected to be less than the first reactivity. Thus, the brine solution can be a first brine solution, the fluid containing the alkali metal silicate can be a first fluid, the sealant can be a first sealant, the first brine, first fluid, the first sealant can define a first fluid loss control treatment, and the first fluid loss control treatment can be placed at a first location within the formation. The methods herein can further include pumping a second fluid loss control treatment into the well to a second location within the formation, the second fluid loss control treatment comprising pumping a second brine solution to the second location, pumping a second fluid containing an alkali metal silicate to the second location, and pumping a second sealant to the second location. The second brine solution can be different from the first brine solution, the second fluid containing an alkali metal silicate can be different from the first fluid containing an alkali metal silicate, or both.

[0029] A bridging solid can be added to the brine solution, the alkali metal silicate solution, the sealant, and/or any spacers that may be used, to provide additional; plugging material. Insoluble particles of any convenient material can be added to the brine solution, the alkali metal silicate solution, the sealant, a brine-based sealant, or just suspended in an aqueous or non-aqueous fluid to pump into a well along with the other components described herein. Particles of insoluble (or slightly soluble) minerals such as calcium carbonate (and/or barium carbonate, strontium carbonate, magnesium carbonate, and iron carbonate) calcium oxalate or molybdate, barium sulfate, oxalate, or molybdate, silica, polymers, metals, and combinations thereof, can be used. The particles may be sized to ensure passages having target sizes are plugged. For example, particles having sizes of 0.5 mm to 1.5 mm can be included to plug openings and passages having similar size, along with other components of the system. Particles having sizes of 1.5 mm to 2.5 mm can be included to plug larger openings, Mixtures of particles having different sizes can be used.

[0030] The methods above can be extended by the use of a cementitious material, such as a Portland cement slurry, geopolymer slurry, or another alkali activated aluminosilicate polymerization slurry. Such a material can be pumped after the sealant such that a material having compressive strength is added to the sealing system. The compressive strength of the cementitious material can be selected using conventional means. The cementitious material can be pumped immediately following the sealant, or after the soak time.

Examples

[0031] Four compositions were prepared and subjected to plugging tests. The compositions were prepared, and 75 mL of each composition was placed in a modified fluid loss cell having a 15 mm slot to test plugging effectiveness. In each test, 75 mL of SLB D075 was also added to the cell in contact with the composition, and 130 mL of water-based drilling fluid having bulk density of 10 Ib/gal is positioned on top of the composition within the cell. Each cell is pressurized in a ramped fashion in increments of 100 psi, each pressure increment being maintained for 5 minutes. The four compositions are described in Table 1. In Table 1 , the defoamer is SLB D175A, the viscosifier is xanthan gum, the base fiber is FORM-A-BLOK AS, the enhanced fiber is SLB Losseal Max, part C.

Table 1 - Sealing Compositions

Fluid loss test results are shown in Table 2, which sets forth the volume of free water observed in each cell after each 5 min increment.

Table 2 - Fluid Loss Performance, Observed Cumulative Volume of Free Water, mL

The results in Table 2 show that the formulations including NaCI or CaCl2 brine and sodium silicate were able to plug a 15 mm slot and hold up to 500 psi pressure with acceptably low fluid loss.

[0032] The preceding description has been presented with reference to certain embodiments. Persons skilled in the art and technology to which this description pertains will appreciate that changes in the methods described can be practiced without meaningfully departing from the principle and scope of this subject matter and inventions described herein. Accordingly, the foregoing description should not be read as pertaining only to the precise compositions described, but rather should be read as consistent with and as support for the following claims, which are to be understood as having their fullest and fairest scope.

Claims

CLAIMS We claim:

1. A method, comprising: pumping a brine solution into a well; pumping a fluid containing an alkali metal silicate into the well to contact the brine solution; pumping a sealant into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation.

2. A method, comprising: pumping a brine solution into a well; pumping a fluid containing a sodium silicate, a potassium silicate, or both, into the well; pumping a sealant into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation.

3. A method, comprising: pumping a fluid containing a sodium silicate, a potassium silicate, or both, into the well; pumping a sealant comprising a brine solution, fibers, and particles into the well to restrict flow pathways within the formation; displacing the sealant from the well into a formation adjacent to the well; and reacting the alkali metal silicate with the brine to further restrict flow pathways within the formation.

4. The method of any of claims 1 -3, wherein the brine solution comprises sodium chloride, sodium bromide, calcium chloride, calcium bromide, or a combination thereof.

5. The method of any of claims 1 -4, further comprising pumping a spacer into the well between pumping the fluid containing a sodium silicate, a potassium silicate, or both into the well and pumping the sealant into the well.

6. The method of any of claims 1-5, wherein the brine solution is the base fluid for the sealant.

7. The method of any of claims 1 -6, further comprising, after displacing the sealant from the well, pumping a cementitious material into the well and displacing the cementitious material into the formation.

8. The method of claim 1 , wherein the brine solution contains suspended salt solids, the alkali metal silicate contains suspended alkali metal silicate solids, or both.

9. The method of claim 8, wherein the brine solution is a stabilized suspension, the fluid containing the alkali metal silicate is a stabilized suspension, or both.

10. The method of any of claims 1 to 9, wherein the brine solution, the fluid containing alkali metal silicate, and the sealant contains a bridging solid.

11. The method of any of claims 1 to 10, wherein a composition of the brine solution, a composition of the fluid containing alkali metal silicate, or both, are selected based on a pumping time to place the brine solution, the fluid containing alkali metal silicate, or both, within the formation.

12. The method of any of claims 1 to 11 , wherein the sealant is displaced from the well into the formation adjacent to the well using a drilling mud.

13. The method of any of claims 1 to 12, wherein the brine solution is a first brine solution, the fluid containing the alkali metal silicate is a first fluid, the sealant is a first sealant, the first brine, first fluid, the first sealant define a first fluid loss control treatment, and the first fluid loss control treatment is to be placed at a first location within the formation, and further comprising pumping a second fluid loss control treatment into the well to a second location within the formation, the second fluid loss control treatment comprising pumping a second brine solution to the second location, pumping a second fluid containing an alkali metal silicate to the second location, and pumping a second sealant to the second location.

14. The method of claim 13, wherein the second brine solution is different from the first brine solution, the second fluid containing an alkali metal silicate is different from the first fluid containing an alkali metal silicate, or both.

15. The method of any of claims 1 to 14, wherein the brine solution is a chloride or bromide solution.