Improvement of long-term hydraulic fracture conductivity by strengthening rock via formation of fluorite

Abstract

A method of treating a carbonatite formation includes introducing a stimulation fluid into the carbonatite formation at a pressure greater than a fracture pressure of the formation and creating an opening in the carbonatite formation by the stimulation fluid. A fluoride salt solution, optionally comprising a proppant, may then be introduced into the carbonatite formation such that it at least partially permeates into the opening. The fluoride salt may then react with a carbonatite surface in the carbonatite formation to form fluorite on the surface of the formation, thereby increasing the hardness of the carbonatite formation.

Description

Background Art

[0001] Hydraulic fracturing is a common technique used to create fractures in formations to allow access to additional hydrocarbons downhole. The conductivity of the fractures created is critical to recovering the hydrocarbons exposed through the fractures. Over time, the conductivity of the fractures tends to decrease due to formation closure stresses. The decrease in conductivity is particularly rapid in soft formations such as carbonates and is exacerbated by the use of acids. Problems such as proppant embedment or failure of rough surfaces can result in lower hydrocarbon production. Summary of the invention

[0002] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0003] In one aspect, embodiments disclosed herein relate to a method for treating a carbonate formation, the method comprising introducing a stimulation fluid into the carbonate formation at a pressure greater than the fracture pressure of the formation, creating openings in the carbonate formation with the stimulation fluid, introducing a fluoride salt solution into the carbonate formation so that it at least partially penetrates into the openings, and allowing the fluoride salt to react with the surface of carbonate rock in the carbonate formation to form fluorite on the surface of the formation, thereby increasing the hardness of the carbonate formation.

[0004] On the other hand, embodiments disclosed herein relate to a method for treating a carbonate formation, the method comprising: introducing a stimulation fluid into the carbonate formation at a pressure greater than the fracture pressure of the formation, creating openings in the carbonate formation with the stimulation fluid, introducing a fluoride salt solution containing a proppant into the carbonate formation so that it at least partially penetrates into the openings, and reacting the fluoride salt with the surface of carbonate rock in the carbonate formation to form fluorite on the surface of the formation, thereby increasing the hardness of the carbonate formation.

[0005] Other aspects and advantages of the claimed subject matter will be apparent from the following description and appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] Figure 1 is a block flow diagram of a method according to one or more embodiments.

[0007] Figure 2A is a graph of XRD data of samples of the present invention and control samples according to one or more embodiments.

[0008] Figure 2B is a graph of XRD data of samples of the present invention and control samples according to one or more embodiments.

[0009] Figure 3A is a SEM image of an untreated carbonate rock sample according to one or more embodiments.

[0010] Figure 3B is a SEM image of a carbonate rock sample processed according to one or more embodiments.

[0011] Figure 4A is a graph showing hardness data for a sample of Austin chalk.

[0012] Figure 4B is a graph showing hardness data for a sample of Indiana Limestone. DETAILED DESCRIPTION

[0013] The present disclosure generally relates to methods for hardening carbonate rocks to reduce problems associated with reduced fracture conductivity. The hardness of carbonate formations can be increased by introducing a fluoride brine solution into the formation. The fluoride salt reacts with the carbonate surface to form a layer of fluorite within the formation. Fluorite is harder than carbonate rock, so fracture conductivity can be better maintained in formations treated with fluoride salts as described herein.

[0014]

[0013] In one aspect, embodiments disclosed herein relate to a method of treating a hydrocarbon-bearing formation. Figure 1 A method 100 is shown according to one or more embodiments of the present disclosure. First, a stimulation fluid may be introduced into a carbonate formation at a pressure greater than the fracture pressure of the formation (step 102). The stimulation fluid may be, for example, a fracturing fluid, and in certain embodiments may include an acid.

[0015] The fracturing fluid of one or more embodiments may include, for example, a water-based fracturing fluid. In one or more embodiments, the water-based fracturing fluid may include an aqueous fluid. The aqueous fluid may include at least one of fresh water, seawater, brine, water-soluble organic compounds, and mixtures thereof. The aqueous fluid may include fresh water formulated to contain various salts. The salt may include, but is not limited to, alkali metal halides and hydroxides. In one or more embodiments, the brine may be any one of seawater, an aqueous solution in which the salt concentration is lower than that of seawater, or an aqueous solution in which the salt concentration is higher than that of seawater. The salts found in seawater may include sodium, calcium, aluminum, magnesium, potassium, strontium, and lithium salts of halides, carbonates, chlorates, bromates, nitrates, oxides, phosphates, etc. Any of the above salts may be included in the brine. In one or more embodiments, the density of the aqueous fluid may be controlled by increasing the salt concentration in the brine, although the maximum concentration is determined by the solubility of the salt. In a particular embodiment, the brine may include an alkali metal halide or a carboxylate and / or an alkaline earth metal carboxylate.

[0016] Fracturing fluid can be used alone to fracture the formation. Alternatively, fracturing fluid can be used with sufficient proppants. These proppants can include gravel, sand, bauxite or glass beads. Proppant can be uncoated or coated with resin, such as epoxy resin, furan resin, novolak, polyepoxide resin, furan / furan methanol resin (furan / furfuryl alcohol resin, or furan / furfuryl alcohol resin), phenolic resin (phenolic resin), urea-formaldehyde resin, polyurethane resin, phenolic / latex resin, phenol formaldehyde resin, polyester resin and acrylic resin and copolymers and mixtures thereof. The particle size of proppant can be about 2 to about 400 mesh U.S. sieve series. The weight range of the granular material of each gallon of slurry of the fluid slurry obtained can be from as low as about 1ppg to as high as about 20ppg, or from about 5ppg to about 20ppg. Ppg is the pounds of proppant in each gallon of fracturing fluid.

[0017] The fracturing fluid may also include one or more acids. The acid may be any suitable acid known to those of ordinary skill in the art, and its selection may be determined by the intended application of the fluid. In some embodiments, the acid may be one or more selected from the group consisting of hydrochloric acid, sulfuric acid, carboxylic acid (such as acetic acid) and hydrofluoric acid. In some embodiments, hydrofluoric acid may be included as a hydrogen fluoride source, such as ammonium fluoride, ammonium bifluoride, fluoroboric acid, hexafluorophosphoric acid, etc.

[0018] The fracturing fluid of one or more embodiments may include a total amount of one or more acids in the range of about 0.01 to 30.0 wt %. For example, the fracturing fluid may include an amount of acid in the range of a lower limit of 0.01, 0.05, 0.1, 0.5, 1.0, 5.0, 10, 15, 20, and 25 wt % to an upper limit of 0.5, 1.0, 5.0, 10, 15, 20, 25, and 30 wt %, wherein any lower limit may be used in combination with any mathematically compatible upper limit.

[0019] The fracturing fluid of one or more embodiments may include one or more additives. The additive may be any conventionally known one, and with the benefit of this disclosure, one of ordinary skill in the art will appreciate that the selection of the additive will depend on the intended application of the fracturing fluid. In some embodiments, the additive may be one or more selected from a clay stabilizer, a scale inhibitor, a corrosion inhibitor, a biocide, a friction reducer, a thickener, a fluid loss additive, and the like.

[0020] The fracturing fluid of one or more embodiments may include a total amount of one or more additives in the range of about 0.01 to 15.0 weight %. For example, the fracturing fluid may include an additive in an amount in the range of a lower limit to an upper limit, wherein the lower limit is any one of 0.01, 0.05, 0.1, 0.5, 1.0, 2.5, 5.0, 1.5, 10.0, and 12.5 weight %, and the upper limit is any one of 0.1, 0.5, 1.0, 2.5, 5.0, 7.5, 10.0, 12.5, 15.0, 20.0, and 30.0 weight %, wherein any lower limit may be used in combination with any mathematically compatible upper limit.

[0021] Return to reference Figure 1 , a stimulation fluid 102 is introduced at a pressure greater than the fracture pressure of the formation, creating openings 104 in the carbonate formation. When the stimulation fluid does not contain an acid, the openings may simply be cracks created in the formation by the pressure of the fracturing fluid. In embodiments where the fracturing fluid contains a proppant, the proppant may be used to prop the cracks open and maintain connectivity of the cracks.

[0022] The well stimulation process of one or more embodiments can be a matrix stimulation process. In the matrix stimulation process of one or more embodiments, the stimulation fluid contains acid. The acid may react with the formation, dissolve the rock, and produce wormholes, thereby creating a path for hydrocarbons to move out from deeper inside the rock. When wormholes are produced by acid stimulation, rough surfaces or uneven surfaces are produced due to the interaction between the acid and the carbonate surface. These rough surfaces serve as supports for the cracks, keeping them open. However, acid has a tendency to soften rock. Therefore, the rough surface is softened and is easily deformed and broken when subjected to high stresses during the process of extracting hydrocarbons from the formation, thereby reducing the conductivity of the opening in the formation.

[0023] In order to enhance the surface of the carbonate formation after the increase in production, the method 100 according to one or more embodiments includes step 106, introducing a fluoride salt solution into the carbonate formation so that it at least partially penetrates into the opening. The fluoride salt solution can be an aqueous solution. The aqueous solution can include at least one of fresh water, seawater, brine, water-soluble organic compounds and mixtures thereof. The aqueous fluid can include fresh water formulated to contain various salts other than fluoride salts. The salt can include, but is not limited to, alkali metal halides and hydroxides. In one or more embodiments, the brine can be any one of seawater, an aqueous solution in which the salt concentration is lower than the salt concentration of seawater, or an aqueous solution in which the salt concentration is higher than the salt concentration of seawater. The salts found in seawater can include sodium, calcium, aluminum, magnesium, potassium, strontium and lithium salts of halides, carbonates, chlorates, bromates, nitrates, oxides, phosphates, etc. Any of the above salts can be included in the brine.

[0024] The fluoride salt in the fluoride salt solution can be sodium fluoride (NaF) or ammonium fluoride (NH4F). In a specific embodiment, the fluoride salt is NaF. The concentration of the fluoride salt in the fluoride salt solution can be in the range of 0.1 to 1.2 molar (M). The concentration of the fluoride salt can have a lower limit and an upper limit, the lower limit being any one of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6 and 0.7 M, and the upper limit being any one of 0.7, 0.8, 0.9, 1.0, 1.1 and 1.2 M, wherein any lower limit can be used in pair with any mathematically compatible upper limit. The concentration used can depend on the temperature of the solution or the temperature at which the solution is used in the formation, and the specific fluoride salt or mixture of salts used.

[0025] After the fluoride salt solution is introduced into the formation (step 106), the fluoride salt solution can be maintained inside the formation for a period of time, referred to as the "soak time". The soak time of the fluoride salt solution can be about 24 to 480 hours. For example, the soak time can have a lower limit and an upper limit, the lower limit is any one of 24, 48, 72, 96, 120, 180, 240 hours, and the upper limit is any one of 96, 120, 180, 240, 300, 360, 420, 480 hours, wherein any lower limit can be used in pair with any mathematically compatible upper limit.

[0026] Once introduced into the carbonate formation 106, the fluoride salt reacts with the carbonate surface in the carbonate formation to form fluorite 108 on the surface of the formation. In one or more specific embodiments, fluorite is formed on the surface of the formation after about 120 hours of soaking time. Because fluorite is a harder mineral than carbonate, the presence of fluorite on the surface of the carbonate increases the hardness of the carbonate formation. This increase in hardness can reduce problems associated with the decrease in fracture conductivity over time.

[0027] However, as will be appreciated by those skilled in the art, as fluoride salts react with carbonate rocks inside the formation, the concentration of fluoride salts in the fluoride salt solution decreases. This reduction in concentration may reduce the reaction rate inside the formation. Therefore, after a given soaking time of the first fluoride salt solution, an additional fluoride salt solution may be introduced into the formation. For example, in one or more embodiments, after the soaking time of the first fluoride salt solution, a second amount of the above-mentioned fluoride salt solution may be introduced into the formation. In particular, the first fluoride salt solution may be introduced into the formation and maintained within the formation for a period of about 24 to 120 hours. Then, a second amount of fresh fluoride solution may be introduced into the formation and maintained within the formation for an additional 24 to 120 hours. The introduced fresh fluoride salt solution may then react with the unreacted portion of the carbonate formation (particularly the area near the wellbore), further increasing the hardness of the formation in these areas. The introduction of additional fluoride salt solution may also push the first fluoride salt solution into a deeper depth in the formation, thereby promoting the hardening of the surface farther from the wellbore. In order to achieve the desired internal hardness of the formation, fresh fluoride salt solution can be introduced into the formation any number of times. For example, one injection, two injections, three injections, four injections, five injections, six injections or more of fresh fluoride salt solution can be introduced downhole. Each injection of fluoride salt solution can have a concentration as described above and can be maintained in the formation for a suitable soaking time as described above.

[0028] As described above, fluorite is harder than carbonate rock. Therefore, a formation that has been treated with the sodium fluoride solution of one or more embodiments to form a layer of fluorite on the surface of the formation can have an increased hardness. The hardness of the formation can be measured according to any technique known in the art. For example, in a particular embodiment, the hardness of a formation, or a rock sample representing or from a formation can be measured by a Brinell hardness device. As measured by such a device, a formation that has been treated with a sodium fluoride solution can show a 4% to 6% increase in hardness over the same formation before treatment. As will be appreciated by those skilled in the art, different hardness measurement techniques may result in different hardness values.

[0029] As described above, the fracturing fluid of one or more embodiments may contain a proppant. However, it is not necessary to contain a proppant. In fact, in some embodiments of the present disclosure, the proppant is contained in an aqueous fluoride salt solution. Therefore, the proppant is introduced into the carbonate formation together with the fluoride salt solution, so that the proppant stays in the cracks while the formation is hardened by the fluoride salt solution. As described above, multiple injections of the fluoride salt solution can be performed. In this way, the proppant can be contained in any fluoride salt solution introduced into the formation. In a specific embodiment in which two fluoride salt solution injections are performed, the proppant can be contained in, for example, the second injection. In other embodiments, a production-enhancing fluid containing a proppant can be introduced into the formation after the fluoride salt solution is introduced. After completing the steps of the method described herein, hydrocarbons can be produced from the formation as in normal operation.

[0030] Embodiments of the present disclosure may provide at least one of the following advantages. Methods according to the present disclosure may result in an increase in the hardness of a carbonate formation compared to a carbonate formation not treated with a fluoride salt solution. The treated formation with increased hardness may provide better fracture conductivity over time, even during periods of stress (such as hydrocarbon production).

[0031] Example

[0032] Two types of carbonate rocks (Austin Chalk or "CH" and Indiana Limestone "LS") were tested. CH and LS, both containing greater than 97% calcium carbonate (CaCO3), were obtained from a local supplier. Sodium fluoride (≥99%) was obtained from Sigma-Aldrich. CH and LS blocks were cylindrical, measuring 3 inches in length and 2.5 inches in diameter.

[0033] The crystal structure of the sample was measured using X-ray diffraction (XRD) on an Empyrean XRD (Malvern Panalytical company). Small pieces were peeled off from the sample and then crushed into powder for analysis. Imaging and elemental analysis were performed on a JCM-7000NeoScope scanning electron microscope (SEM). Small pieces were peeled off from the sample for SEM analysis. The hardness of the sample was tested using an indentation technique on a FH-9 (Tinius Olsen) Brinell hardness tester. In brief, an indentation was produced on all rocks with a 5mm ball, 62.5kgf (613N) was applied to the chalk sample and 125kgf (1226N) was applied to the limestone sample. Then, the average diameter of each indentation was measured to determine the surface area. The Brinell hardness as the ratio of force to indentation area was then calculated.

[0034] The Austin chalk sample and the Indiana limestone sample were characterized by XRD and SEM to obtain the baseline physical properties of the samples. Hardness testing was then performed. These comparative samples are referred to as Comparative CH and Comparative LS.

[0035] Then, the CH and LS samples were treated with NaF by dissolving 16.8 g of NaF in 450 ml of deionized water to form a 0.9 M NaF solution. Then, the CH and LS samples were immersed in the NaF solution for 120 hours. After immersion in the NaF solution, the CH and LS samples were rinsed with deionized water and dried at room temperature for one week. The CH and LS samples were characterized and tested according to the same protocol as the comparative samples.

[0036] The X-ray diffraction data of the samples were Figure 2A (Austin Chalk sample) and Figure 2B (Indiana limestone sample). The bottom trace in both figures is the control sample, and the top trace in both figures is the sample treated with NaF. The results of XRD analysis show that NaF treatment leads to the formation of new peaks in the XRD spectrum, which confirms the formation of new compounds. In the XRD spectrum of the rock treated with NaF, new peaks appear at 2θ values ​​of 28.3°, 47.1°, and 56.0°. These peaks are identified as fluorite minerals (CaF2).

[0037] The changes in mineralogy were also confirmed by SEM imaging. Figure 3A (untreated rock samples) and Figure 3B (processed rock sample). The newly formed minerals cover the rock grains, creating an interconnected network, such as Figure 3B To compare the composition of treated and untreated particles, select Figure 3BEnergy dispersive X-ray spectroscopy (EDS) was performed on several surface points of the samples shown. Figure 3B In the figure, point P2 represents the parent CaCO3 particle (i.e., the untreated sample). Point P1 is located on the particle covered by the newly formed mineral rich in fluorine atoms. The elemental analysis results of point P1 (treated) and point P2 (CaCO3) are shown in Table 1 below.

[0038] Table 1: Elemental analysis by EDS

[0039] point carbon% oxygen% fluorine% sodium% calcium% gold% total% P1 6.48 8.11 28.86 4.1 34.66 17.79 100 P2 6.77 5.06 3.78 0.45 72.65 11.29 100

[0040] For point P1, the ratio of calcium to fluorine is about 1:2, consistent with the molecular formula of CaF2. In contrast, at point P2, very little fluorine was detected.

[0041] The hardness of each sample was tested and the results were reported in Figure 4A (CH) and Figure 4B The Brinell hardness test confirmed that the average hardness in the chalk sample increased by 6%, while the hardness in the limestone sample increased by 3.8%.

[0042] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications may be made to the example embodiments without materially departing from the present invention. All such modifications are therefore intended to be included within the scope of the present disclosure as defined by the appended claims. In the claims, means-plus-function clauses are intended to cover structures described herein that perform the recited functions, and to cover not only structural equivalents but also equivalent structures. Thus, while nails and screws may not be structural equivalents because nails employ a cylindrical surface to secure wooden parts together while screws employ a helical surface, nails and screws may be equivalent structures in the context of fastening wooden parts. Applicant expressly disclaims any limitation of any claim herein to 35 U.S.C. §112(f) unless a claim expressly uses the term "means for..." and an associated function.

Claims

1. A method for treating a carbonate formation, the method comprising: introducing a stimulation fluid into the carbonate formation at a pressure greater than a fracture pressure of the formation; creating openings in the carbonate formation with the stimulation fluid; introducing a fluoride salt solution into the carbonate formation such that it at least partially penetrates into the opening; and The fluoride salt is reacted with a carbonate rock surface in the carbonate formation to form fluorite on the surface of the formation, thereby increasing the hardness of the carbonate formation.

2. The method of claim 1, wherein the stimulation fluid is selected from the group consisting of an acidizing fluid, a fracturing fluid, and combinations thereof.

3. The method of claim 1 or 2, wherein the stimulation fluid comprises a proppant.

4. The method of any one of claims 1 to 3, further comprising, after reacting the fluoride salt with the carbonate rock, introducing additional stimulation fluid comprising a proppant into the carbonate formation.

5. The method according to any one of claims 1 to 4, wherein the concentration of the fluoride salt in the fluoride salt solution is 0.1 to 5.0 M.

6. The method of claim 5, wherein the fluoride salt is selected from the group consisting of NaF, NH4F, and combinations thereof.

7. The method of any one of claims 1 to 6, further comprising, after introducing the fluoride salt solution into the carbonate formation, maintaining the fluoride salt solution in the formation for a time in the range of 24 to 480 hours.

8. The method of claim 7, further comprising, after said maintaining, introducing additional fluoride salt solution into said carbonate formation.

9. The method according to any one of claims 1 to 8, further comprising producing hydrocarbons from the carbonate formation.

10. A method for treating a carbonate formation, the method comprising: introducing a stimulation fluid into the carbonate formation at a pressure greater than a fracture pressure of the formation; creating openings in the carbonate formation with the stimulation fluid; introducing a fluoride salt solution containing a proppant into the carbonate formation such that it at least partially penetrates into the opening; and The fluoride salt is reacted with a carbonate rock surface in the carbonate formation to form fluorite on the surface of the formation, thereby increasing the hardness of the carbonate formation.

11. The method of claim 10, wherein the stimulation fluid is selected from the group consisting of an acidizing fluid, a fracturing fluid, and combinations thereof.

12. The method according to claim 10 or 11, wherein the concentration of the fluoride salt in the fluoride salt solution is 0.1 to 5.0 M.

13. The method of claim 12, wherein the fluoride salt is selected from the group consisting of NaF, NH4F, and combinations thereof.

14. The method of any one of claims 10 to 13, further comprising, after introducing the fluoride salt solution containing the proppant into the carbonate formation, maintaining the fluoride salt solution in the formation for a time in the range of 24 to 480 hours.

15. The method of claim 14, further comprising, after said maintaining, introducing additional fluoride salt solution into said carbonate formation.

16. The method of any one of claims 10 to 15, further comprising producing hydrocarbons from the carbonate formation.

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