METHOD OF ARTIFICIALLY REDUCING POROSITY

Abstract

The present invention relates to artificially reducing the porosity of any potential flow paths in the near-wellbore region of a well or in permeable zones within or surrounding a well. In doing so, the permeability in this the targeted region will be significantly reduced, thus, preventing unwanted flow of subsurface fluids. The present invention concerns a method comprising applying a first and second solution comprising scale precursors to the porous media, wherein following this application, at least a portion of the scale precursors form at least two insoluble salts. Additionally, the present invention concerns a kit of parts comprising the first and second solutions.

Claims

1. A method of reducing the porosity of porous media of the near-wellbore wherein the method comprises: a) applying a first solution comprising a first and second scale precursor in the form of soluble ions to the porous media; b) applying a second solution comprising a third and fourth scale precursor in the form of soluble ions to the porous media; wherein following steps a and b, at least a portion of the scale precursors form at least two insoluble salts.

2. The method of claim 1 wherein the method further comprises repeating steps a) and b).

3. The method of claim 1 where following one or more applications of steps a) and b), the egress of fluids from the porous medium of the near wellbore and their inflow into the well is reduced or stopped.

4. The method of claim 1, wherein the method further comprises applying either or both of a cement plug or a mechanical plug to the wellbore.

5. The method of claim 1, wherein the first and second solutions are miscible.

6. The method of claim 1, where the steps a) and b) are performed consecutively or concurrently.

7. The method of claim 1, wherein the second solution is prepared in situ using an acidic brine solution in combination with solids present in the wellbore.

8. The method of claim 5 wherein the steps a) and b) are performed consecutively, wherein the method further comprises applying a spacer solution or spacer device to the porous media between steps a) and b).

9. The method of claim 8 wherein either: a) the spacer solution has the same miscibility as the first and second solutions, or; b) the spacer solution is not miscible with the first solution, but the miscibility of the spacer solution within the first solution improves on mixing with the second solution.

10. The method of claim 1, wherein the method further comprises applying a pre-flush solution to the porous media, wherein the pre flush solution comprises an amphiphile, a surfactant or a combination thereof.

11. The method of claim 1, wherein either or both of the first or second solutions are non-aqueous.

12. The method of claim 10 wherein a non-aqueous solution comprises a glycol ether amphiphile, preferably one or more selected from a group comprising ethylene glycol, ethylene glycol monobutyl ether and diethylene glycol monobutyl ether.

13. The method of claim 1 wherein either or both of the first or second solutions are aqueous.

14. The method of claim 12 wherein an aqueous solution comprises seawater, produced water, KCl brine or low salinity brine.

15. The method of claim 1, wherein the first and second scale precursors are selected from a group comprising: a) cations selected from: i. group 2 alkali earth metals optionally Ca.sup.2+, Sr.sup.2+ and Ba.sup.2+, or; ii. polyatomic cations, optionally NH.sup.4+, and; b) anions selected from: i. the halides group optionally F, Cl, Br or I, ii. an oxide anion or; iii. a polyatomic anion, optionally CH.sub.3COO, CO.sub.3.sup.2, or a hydroxide anion.

16. The method of claim 14 wherein the first solution further comprises cations and/or anions selected from a group comprising the following, besides the first and second scale precursors a) cations selected from: i. group 2 alkali earth metals optionally Ca.sup.2+, Sr.sup.2+ and Ba.sup.2+, or; ii. polyatomic cations, optionally NH.sup.4+, and; b) anions selected from: i. the halides group optionally F, Cl, Br or I, ii. an oxide anion or; iii. a polyatomic anion, optionally CH.sub.3COO, CO.sub.3.sup.2, or a hydroxide anion.

17. The method of claim 1, wherein the third and fourth scale precursors are different from the first and second scale precursors and are selected from a group comprising the following: a) cations selected from the transition metal group, optionally a cation selected from the 5th period transition metal group, further optionally Mn.sup.2+ or Cu.sup.2+, and; b) a polyatomic anion, optionally SO.sub.4.sup.2.

18. The method of claim 17 wherein the second solution further comprises cations and/or anions selected from a group comprising the following, besides the third and fourth scale precursors: a) cations selected from the transition metal group, optionally a cation selected from the 5th period transition metal group, further optionally Mn.sup.2+ or Cu.sup.2+, and; b) a polyatomic anion, optionally SO.sub.4.sup.2.

19. The method of claim 1, wherein the at least two insoluble salts may be selected from a group comprising: a) a group 2 metal sulphate optionally BaSCU, SrSCU or CaSCU, and; b) a transition metal salt of halide, oxide, hydroxide optionally CuI, Cu, CU(OH).sub.2, CuBr.sub.2, CU(CH.sub.3COO).sub.2, MnI.sub.2, Mn(OH).sub.2, MnBr.sub.2, Cu.sub.2O, CuO, MnO, Mh.sub.3q.sub.4, Mn.sub.2O.sub.3, MnO.sub.2, Cu.sub.2CO.sub.3(OH).sub.2 or MnCO.sub.3.

20. The method of claim 1, wherein one or more of the scale precursors are provided at concentrations greater than 100 g/100 ml.

21. The method of claim 1, wherein either or both of the first or second solutions comprise an amphiphilic solvent.

22. The method of claim 21 wherein the amphiphilic solvent is monoethylene glycol.

23. A kit comprising: first and second solutions; the first solution comprising a first and second scale precursor in the form of soluble ions to the porous media; and the second solution comprising a third and fourth scale precursor in the form of soluble ions to the porous media, wherein at least a portion of the scale precursors form at least two insoluble salts.

24. The method of claim 1, wherein: a) the first solution comprises barium iodide (BaI.sub.2) and barium acetate (Ba(CH.sub.3COO).sub.2) as the first, second and other scale precursors, 15% ethylene glycol (MEG) and sulphate-free seawater, b) the second solution comprises copper sulphate (CuSCU) and manganese sulphate (MnSCU) as the third, fourth and other scale precursors, 15% ethylene glycol MEG and seawater, and; the method further comprises: I. applying a pre-flush solution comprising 15% ethylene glycol monobutyl ether (EGMBE) in sulphate-free seawater to the porous media, II. applying a spacer solution comprising sulphate-free seawater to the porous media, prior to the application of the second solution, III. repeating steps a) and b) as required until the egress of fluids from the porous medium of the near-wellbore and their inflow into the well is reduced or stopped.

25. The method of claim 1, wherein: the method further comprises: I. applying calcium carbonate solids to the open hole/perforations in the porous media, either part of the way or all the way to the top perforations II. applying a spacer solution comprising sulphate-free seawater to the porous media, prior to the application of the second solution, III. applying hydrofluoric acid to the porous media, optionally doped with small concentrations of hydrochloric acid, IV. repeating steps a) and b) as required until the egress of fluids from the porous medium of the near-wellbore and their inflow into the well is reduced or stopped, and; wherein; a) the first solution comprises a copper-rich brine, optionally CuSCU as the first and second scale precursors, optionally further comprising a buffer, b) the second solution is created in situ by a reaction between the hydrofluoric acid and the calcium carbonate solids, to form the third and fourth scale precursor.

Description

BRIEF DESCRIPTION OF THE FIGURES

[0092] FIG. 1: Table 1: Experimentally observed solubilities for two of the first solution precursors compared with the results in the literature.

[0093] FIG. 2: Table 2: Experimentally observed solubilities for two of the second solution precursors compared with the results in the literature.

[0094] FIG. 3: Table 3: Precipitation levels expected on mass and % v/v basis for few cases.

[0095] FIG. 4: Test glass bottles after mixing first and second solutions of scale precursors. Precipitation observed from few pairings of the first and second solutions.

[0096] FIG. 5: A schematic of the experimental setup of the visualisation experiment of FIG. 6.

[0097] FIG. 6: A micromodel experiment: Placement after barium iodide precursor is injected (first), after copper sulphate precursor was introduced (second), copper sulphate precursor progressed (third), full blockage (fourth). Dark colour is the precipitate blocking light from the light source underneath micromodel. (a) BI.sub.2 flooding and pre-flush displacement (b) CuSO.sub.4 flooding and initial precipitation (c) Propagation of the mineral precipitation (d) Seal placed in-situ in the porous medium.

[0098] FIG. 7: A schematic of the experimental setup of the sand-pack experiment of FIG. 8.

[0099] FIG. 8: Sand-pack column before and after (rotated in three positions) the flooding experiment. Co-precipitation is clearly visible (black, white and brown precipitates).

[0100] FIG. 9: Perforated oil well requiring a sub-surface isolation.

[0101] FIG. 10: Fluid fronts at treatment end with good placement.

[0102] FIG. 11: Fluid fronts at treatment end with inadequate placement.

[0103] FIG. 12: The parameters of the reservoir model used to investigate subsurface mixing.

[0104] FIG. 13: Mixing in the subsurface (blue=no mixing; red=perfect mixing).

[0105] FIG. 14: Use of Cu rich brine, HF and CaCO.sub.3 proppants to ensure near-wellbore placement.

DEFINITIONS

[0106] Throughout the specification, unless the context demands otherwise, the terms ‘comprise’ or ‘include’, or variations such as ‘comprises’ or ‘comprising’, ‘includes’ or ‘including’ will be understood to imply the inclusion of a stated integer or group of integers, but not the exclusion of any other integer or group of integers.

[0107] As used herein, the articles “a” and “an” refer to one or to more than one (for example to at least one) of the grammatical object of the article.

[0108] “About” shall generally mean an acceptable degree of error for the quantity measured given the nature or precision of the measurements.

[0109] As used herein, “rock features” includes porous media, throats, fissures, cracks or other voids which are accessed by the subsurface well.

[0110] As used herein, “insoluble” is a solid with low solubility (<10-3 g/100 ml) and high stability in aqueous media.

[0111] An embodiment of the present invention will now be described by way of example only, with reference to the accompanying figures.

DETAILED DESCRIPTION OF THE INVENTION

Example 1: Preparation of Primary Solutions and Chemical Reactions

[0112] To prepare first solutions, the following solutions were created: [0113] A solution of 15% monoethylene glycol (MEG) and varying concentrations of BaI.sub.2 or Ba(CH.sub.3COO).sub.2 in sulphate-free seawater:

BaI.sub.2(s).fwdarw.Ba.sup.2+.sub.(aq)+2I.sup.−.sub.(aq)

Ba(CH.sub.3COO).sub.2(s).fwdarw.Ba.sup.2+.sub.(aq)+2(CH.sub.3COO).sup.−.sub.(aq)

[0114] In performing the above solutions, a saturation index equal or less than one was maintained to achieve a stable solution.

[0115] To prepare second solutions, the following solutions were created: [0116] A solution of 15% MEG and varying concentrations of CuSO.sub.4 and MnSO.sub.4 in sulphate-free seawater:

CuSO.sub.4(s).fwdarw.Cu.sup.2+.sub.(aq)+SO.sub.4 (aq).sup.2−

MnSO.sub.4(s).fwdarw.Mn.sup.2+.sub.(aq)+SO.sub.4 (aq).sup.2−

[0117] In performing the above solutions, a saturation index equal or less than one is maintained to achieve a stable solution.

[0118] The above precursors were tested in separate simplified formulations to verify if the solubilities published in the literature can in fact be realised (Green, 1997; Trimble, 1931). The results in FIG. 1 (Table 1) and FIG. 2 (Table 2) demonstrate this, with very high loadings (solubility >100 g/100 ml) possible. The differences between the observed and literature solubilities are most likely due to different brine compositions and due to the dissolution experiments being conducted over a 24 hour period only without checking if saturation has been attained. The latter was opted for as demonstrating high loadings at limited solubilisation time is sufficient for the purposes of this work.

[0119] When the first and the second solutions were mixed, depending on the reservoir mineralogy, the following reactions were observed:

[00001]$\begin{array}{c}•{\mathrm{Ba}}_{\left(aq\right)}^{2+}+{\mathrm{SO}}_{4\left(\mathrm{aq}\right)}^{2-}.fwdarw.{\mathrm{BaSO}}_{4\left(s\right)}\\ •2I_{\left(aq\right)}^{-}.fwdarw.I_{2\left(s\right)}\\ •{\mathrm{Cu}}_{\left(aq\right)}^{2+}+6H_2{O}_{\left(l\right)}.fwdarw.{\left[{\mathrm{Cu}\left(H_{2}O\right)}_6\right]}_{\left(aq\right)}^{2+}\\ {•\left[{\mathrm{Cu}\left(H_{2}O\right)}_6\right]}_{\left(aq\right)}^{2+}+2{\mathrm{OH}}_{\left(aq\right)}^{-}.fwdarw.{\mathrm{Cu}\left(\mathrm{OH}\right)}_{2\left(s\right)}+6H_2{O}_{\left(l\right)}\\ •{\mathrm{Cu}\left(\mathrm{OH}\right)}_{2\left(s\right)}\stackrel{\Delta }{.fwdarw.}{\mathrm{CuO}}_{\left(s\right)}+6H_2{O}_{\left(l\right)}\\ •{\mathrm{Cu}}_{\left(aq\right)}^{2+}+{\mathrm{CO}}_{3\left(\mathrm{aq}\right)}^{2-}+2{\mathrm{OH}}_{\left(aq\right)}^{-}.fwdarw.{\mathrm{Cu}}_2{{\mathrm{CO}}_3\left(\mathrm{OH}\right)}_{2\left(s\right)}\\ •{\mathrm{Cu}}_{\left(aq\right)}^{2+}+2I_{\left(aq\right)}^{-}.fwdarw.{\mathrm{CuI}}_{2\left(s\right)}\\ •{\mathrm{CuI}}_{2\left(s\right)}\stackrel{\Delta }{.fwdarw.}2{\mathrm{CuI}}_{\left(s\right)}+I_{2\left(s\right)}\\ •{\mathrm{Mn}}_{\left(aq\right)}^{2+}+6H_2{O}_{\left(l\right)}.fwdarw.{\left[{\mathrm{Mn}\left(H_{2}O\right)}_6\right]}_{\left(aq\right)}^{2+}\\ {•\left[{\mathrm{Mn}\left(H_{2}O\right)}_6\right]}_{\left(aq\right)}^{2+}+2{\mathrm{OH}}_{\left(aq\right)}^{-}.fwdarw.{\mathrm{Mn}\left(\mathrm{OH}\right)}_{2\left(s\right)}+6H_2{O}_{\left(l\right)}\\ •{\mathrm{Mn}\left(\mathrm{OH}\right)}_{2\left(s\right)}\stackrel{\Delta }{.fwdarw.}{\mathrm{MnO}}_{\left(s\right)}+6H_2{O}_{\left(l\right)}\\ •{\mathrm{Mn}}_{\left(aq\right)}^{2+}+{\mathrm{CO}}_{3\left(\mathrm{aq}\right)}^{2-}.fwdarw.{\mathrm{MnCO}}_{3\left(s\right)}\end{array}$

[0120] At saturation (maximum precipitation conditions), few reaction cases were tested based on the experimental results in Table 1 and Table 2. Considering each of the investigated precipitates separately, the precipitation levels and pore volume (injected volume) occupation results are provided in FIG. 3 (Table 3). This demonstrates at least 5% v/v precipitation expected and more likely more than 20% v/v precipitation.

Example 2: Mixing and In-Situ Precipitation

[0121] Direct observation of in-situ mixing and precipitation was achieved with the aid of flooding experiments in a 3D printed micromodel. A visualisation rig was used to perform the experiment (FIG. 5 and FIG. 6). The micromodel consisted of heterogenous grains at 500 μm or 1000 μm in diameter, with an average porosity of 80% (deliberately high to enable visualising the precipitation and to assess whether blockage is possible at this extreme). The micromodel was initially flooded with a BaI.sub.2 solution followed immediately by a CuSO.sub.4 solution. The injection was done at a rate of 0.05 ml/min to achieve strongly advective flow (Peclet number, Pe=1885>>10, is a dimensionless number defining the ratio of convective to diffusive flow). The results in FIG. 6 demonstrate: [0122] 1) Injection of the solutions separately can achieve the desired in-situ mixing within the pore space, and not only displacement, despite operating in a strongly advective flow regime. [0123] 2) The precipitates form immediately on contact between the first and the second solution as per the design of this concept. [0124] 3) In roughly 10 seconds, a seal is formed in the entire pore volume of the micromodel. The precipitates formed adhered to the gains and prevented further flow without the need for multiple applications in this case.

[0125] Indirect observation of in-situ mixing and precipitation was also investigated under more representative conditions in a sand-pack experiment. A sand-pack rig was used to perform the experiment (FIG. 7 and FIG. 8). The sand-pack column was packed with fine silica sand with average particle size distribution at 120 μm. The column was 1.5 cm in diameter and 19 cm in length, and once packed, was found to have a porosity around 50% (pore volume—15 ml) and a permeability around 1000 mD. Both conditions represent excellent quality of the porous medium for flow conditions, and hence represent an extreme scenario for attempting an in-situ seal.

[0126] In this experiment, two pore volumes of CuSO.sub.4 brine was initially used to flood the sand-pack. This was followed by a quarter pore volume of a KCl brine spacer. On injecting BaI.sub.2 brine at 150 ml/min, after 0.5 pore volume, all injectivity was lost. The precipitation can be observed in FIG. 8 and appears to consist of multiple precipitates. The findings corroborate the findings from the micromodel experiment.

Example 3: Treatment Design

[0127] A key aspect of treatment design on a large-scale will be placement. If the placement is achieved effectively, then the mixing and the precipitation will be enabled more. In this example, a perforated oil well connected to two reservoir layers is considered (FIG. 9). The top layer is more permeable and porous at 300 mD and 25% vs 100 mD and 20% for the bottom layer.

[0128] FIG. 10 demonstrates excellent overlap between the first and second solutions containing the scaling ions which would form the seal. FIG. 11 demonstrates a disconnect in the placement of the first and second solutions in the subsurface, which would not necessarily stop the flow of the reservoir fluids from the bottom reservoir layer, into the top reservoir layer and potentially into the well. Therefore, it is important in assessing the placement to ensure that the reservoir properties are accounted for to ensure a seal covering all flow contributing areas.

Example 4: Modelling the Mixing

[0129] A simple reservoir simulation model was developed to test if the mixing of the first and second solutions can be up-scaled. In this exercise, the reservoir was homogeneous, single phase, isothermal, and two dimensional.

[0130] Top of the reservoir is at depth of 2,000 m, reservoir pressure is 20 kPa with temperature of 90° C. Dimensions of grid blocks around the wellbore are 0.1×0.1×0.1 m. Porosity and permeability are set as uniform 20% and 200 md, respectively (FIG. 12).

[0131] FIG. 13 shows the desired effective mixing around the wellbore as a result of injecting the first and the second solutions separately. The porosity is lost by over 80% in the reservoir model and the injectivity is lost. Access to the well is maintained as demonstrated by the zero mixing within the well itself.

Example 5: Proppant and HF Calculations for the Third Embodiment of the Invention

[0132] This example relates to the third embodiment of the present invention. The methodology is illustrated by the schematic in FIG. 14. The primary reaction driving the near-wellbore seal formation is:

2 Cu.sub.(aq).sup.2+ (in the near−wellbore)+3 Ca.sub.(aq).sup.2+ (released from the proppants)+CO.sub.3 (aq).sup.2− (released from the proppants)+4 F.sub.(aq).sup.− (delivered by the HF formula)+SO.sub.4 (aq).sup.2− (in the near−wellbore)+2 OH.sub.(aq).sup.− (from buffer in the second solution).fwdarw.2 CaF.sub.2(s)+CaSO.sub.4(s)+Cu.sub.2CO.sub.3(OH).sub.2(s)

[0133] The calculations below assumed that only calcium fluoride will precipitate, and represent a small-scale test of the reaction:

[0134] The solubility of CaF.sub.2 in hot water is 0.0017 g/100 ml and its density is 3.18 g/cm.sup.3. Fully utilised 1 kg of proppant yielded:

[0135] 1.00 kg of CaCO.sub.3 proppant gave 9.99 mol Ca.sup.2+;

[0136] 9.99 mol Ca.sup.2+ fully reacted with F.sup.− gave 0.78 kg CaF.sub.2;

[0137] 0.78 kg CaF.sub.2 occupied 245.29 cm.sup.3 of free pore-space.

[0138] Considering a 7 inch (17.78 cm) hole over the 1m length of reservoir section, the pore-space reduction per kg of proppant is:

[00002]$$\begin{gathered} \mathrm{Pore}\mathrm{space}\mathrm{to}\mathrm{plug}=\left(\mathrm{cylindrical}\mathrm{volume}\mathrm{of}\mathrm{plug}\mathrm{as}\frac{\pi }{4}\left(\mathrm{Plug}{\mathrm{Diameter}}^2- \\ \mathrm{Bore}{\mathrm{Diameter}}^2\right)\times \mathrm{length}\right)\times \mathrm{porosity} \end{gathered}$$

[0139] Assuming plug depth in the near-wellbore at least 15 cm and rock with 20% porosity:

[00003]$\mathrm{Volume}\mathrm{to}\mathrm{plug}=\frac{\pi }{4}\times \left({\left(17.78+15\right)}^2-17.78^2\right)\times 100\times 0.2=11,912.92{\mathrm{cm}}^3\mathrm{per}\mathrm{meter}\mathrm{of}\mathrm{length};$

[0140] Pore-space reduction per kg of proppant per meter of reservoir section can be estimated from the 245.29 cm.sup.3 that CaF.sub.2 precipitate occupies divided by the total pore volume of 11,912.92 cm.sup.3. It gives 2.06% pore space reduction form 1 kg of proppant per meter length.

[0141] Thus, following the above small-scale test calculations, which assumes that CaF.sub.2 is all the calcium comes from the proppant only, and CaF.sub.2 to be the only plug forming precipitate, only total of 48.57 kg/m of proppant is required to be injected downhole to create a plug that depth of 15 cm. In practice, a lot less would be required due to the calcium-rich brine in the near-wellbore and the co-precipitation of other co-precipitates as well as precipitates from solids in (from side reactions depending on reservoir fluids/mineralogy e.g. potassium silicofluoride, hydrous silica and calcium fluoride hydrous aluminosilicate). Also, in practice, 100% plugging is not required to destroy the flowing potential of the well.

[0142] In a worst-case scenario estimate, volumes of 3% HF required will be:

[0143] 48.57 kg/m proppant requires 485.24 mol/m HF for full conversion;

[0144] 485.24 mol/m HF is 9.71 kg/m HF;

[0145] At 3% w/v HF acid solution (3 g/100 ml, or 30 g/L), this translates to 323.66 L/m or 2.04 bbl/m of solution per meter length of reservoir section.

[0146] Preferred compositions, features and embodiments of each aspect of the invention are as for each of the other aspects mutatis mutandis unless context demands otherwise.

[0147] Each document, reference, patent application or patent cited in this text is expressly incorporated herein in their entirety by reference, which means it should be read and considered by the reader as part of this text. That the document, reference, patent application or patent cited in the text is not repeated in this text is merely for reasons of conciseness.

[0148] Reference to cited material or information contained in the text should not be understood as a concession that the material or information was part of the common general knowledge or was known in any country.

[0149] Although the invention has been particularly shown and described with reference to particular examples, it will be understood by those skilled in the art that various changes in the form and details may be made therein without departing from the scope of the present invention.

REFERENCES

[0150] Green, D. W., and J. O. Maloney. “Perry's chemical engineers' handbook.” McGraw-Hill (1997). [0151] Gdanski, R. D. (1994, November 1). Fluosilicate Solubilities Affect HF Acid Compositions. Society of Petroleum Engineers. doi:10.2118/27404-PA [0152] Shuchart, C. E. (1995, January 1). HF Acidizing Returns Analyses Provide Understanding of HF Reactions. Society of Petroleum Engineers. doi:10.2118/30099-MS [0153] Shuchart, C. E., & Ali, S. A. (1993, November 1). Identification of Aluminum Scale With the Aid of Synthetically Produced Basic Aluminum Fluoride Complexes. Society of Petroleum Engineers. doi:10.2118/23812-PA [0154] Trimble, H. M. “Solubilities of salts in ethylene glycol and in its mixtures with water.” Industrial & Engineering Chemistry 23, no. 2 (1931): 165-167.