TREATMENT FLUID AND METHODS OF ENHANCING SCALE

SQUEEZE OPERATIONS

BACKGROUND OF INVENTION

Field of the Invention

[0001] Embodiments disclosed herein relate generally to treatment fluids and methods for enhancing scale squeeze operations. In particular, embodiments disclosed herein relate to scale inhibitor promoters for enhancing scale inhibitor adsorption during scale squeeze operations.

Background Art

[0002] Hydrocarbon fluids, such as oil and natural gas, and other desirable formation fluids are obtained from a subterranean geologic formation, i.e., a reservoir, by drilling a well that penetrates the formation zone that contains the desired fluid. It is desirable to maximize the rate of production and the overall amount of hydrocarbon flow from the formation to the surface. One of the factors that influence the rate of hydrocarbon production is the permeability of the formation. The permeability of the formation depends on rock type, pore size, and internal capillaries in the formation. Any constriction in the capillaries or blockage of the pores will cause a reduction in the permeability of the formation and thus reduce the rate of hydrocarbon production.

[0003] In completing or producing subterranean wells in geologic formations, scale formation may become an issue in maintaining productivity of a gas or oil well. Scale formation results when salt in the formation reservoir waters precipitates out and forms scale in the formation. Water may be present in the formation reservoir naturally, or artificially from injecting water into the formation to maintain pressure or to assist in recovery efforts. The formed scale may eventually block the flow paths of the produced oil and gas, thereby reducing the efficiency of the production of the well. Possible solutions to preventing scale formation may include controlling flow rate, pressure, temperature, adding chemical scale inhibitors, and combinations thereof.

[0004] Typical chemical scale inhibitors prevent scale from forming. Among other methods, scale inhibitors may be introduced to a well through methods such as (1)

"squeezing" them at increased pressure into the formation, and let the inhibitors slowly release as production resumes, or (2) adding the inhibitors to brine, and continuously injecting the inhibited brine into the formation. While these treatment methods are effective, multiple treatments may be needed to prevent scale from forming. This may require shutting down production multiple times, reducing overall productivity and increasing costs.

SUMMARY OF INVENTION

[0005] A method of enhancing the lifetime of a scale squeeze treatment, comprising emplacing a scale inhibition promoter in a wellbore region, emplacing a scale inhibitor in the wellbore region; and shutting in the wellbore for a period of time sufficient to initiate adsorption of the scale inhibitor onto the wellbore region.

[0006] A method of minimizing the number squeeze operations needed to inhibit scale formation, comprising emplacing into an geologic formation a scale inhibition promoter of the following formula:

wherein R ¹ may be selected from Ci to C ₂ hydrocarbon radical, C ₁ to C ₄ amino, or C ₁ to C ₄ alkoxy groups; R ² may be a C ₁ to C ₁₂ hydrocarbon radical; and R ³ may each be independently selected from C ₁ to C ₄ alkyl groups; emplacing into the geologic formation a scale inhibitor; depositing the scale inhibitor onto the surface of the geologic formation; initiating production from the geologic formation; and desorbing at least a portion of the deposited scale inhibitor into the produced fluid.

[0007] A treatment fluid for treating a geologic formation, including a base fluid, a scale inhibitor, and a scale inhibition promoter capable of enhancing the adsorption of the scale inhibitor onto the geologic formation surface.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] FIG. 1 shows a graphical representation of scale inhibitor return profiles with and without the scale inhibition promoter.

DETAILED DESCRIPTION

[0009] The inventors of the present disclosure have advantageously discovered that the treatment fluids of the present invention have been optimized for treating a geologic formation and preventing scale formation during production of produced fluids from the geologic formation. Thus, by optimizing a treatment fluid containing scale inhibitor additives designed to minimize scale formation, the lifetime of the scale inhibitor is lengthened, and the overall number of required scale squeeze treatments may be reduced. This reduction in number of scale squeeze treatment minimizes time, costs, and potential damage to the formation. As used herein, "geologic formation" includes both the formation region and the formation matrix.

[0010] Embodiments disclosed herein relate to treatment fluids designed to enhance the effectiveness of scale squeeze operations, and methods of use thereof. In particular, embodiments disclosed herein relate to treating an geologic formationwith a treatment fluid that includes a base fluid, a scale inhibition promoter, anda scale inhibitor; chemically adsorbing the scale inhibitor onto the geologic formation; and producing from the geologic formation at least a portion of the scale inhibitor with produced fluid.

[0011] Scale inhibition promoters suitable for use in the treatment fluids of the present disclosure may include, for example, organosilanes, such as compounds represented by the following structure:

wherein R ¹ may be selected from C ₁ to C ₂ hydrocarbon radical, C ₁ to C ₄ amino or C ₁ to C ₄ alkoxy groups; R ² may be a C ₁ to C ₁₂ hydrocarbon radical; and R ³ may each be independently selected from C ₁ to C ₄ alkyl groups. As used herein, the term "hydrocarbon radical" is intended to refer to radicals primarily composed of carbon and hydrogen atoms, and thus encompasses aliphatic groups such as alkyl and alkenyl. Additionally, the term hydrocarbon radical also includes groups that include heteroatoms, and as such, may include functional groups such as amino groups, ethers, alkoxides, carbonyls, epoxides, amido groups, sulfides, sulfates, carbamates, etc., and combinations thereof. Inclusion of such polar groups may be particularly desirable to aid in dispersibility of the agents in water-based fluids and/or to aid in adsorption of the agent on clay surfaces. In a particular embodiment, a trialkoxysilane may be used. In a particular embodiment, 3- aminopropyltriethoxysilane may be used.

[0012] Such scale inhibition promoters should be present in sufficient concentration to enhance the adsorption of the scale inhibitor to the surface of the geologic formation. For example, in a kaolinite formation, the pseudo-hexagonal plates of the kaolinite clay fines - formed from the layer of tetrahedral SiO ₄ and the layer of octahedral OH ^' -the organosilanes may adsorb on the surface of the kaolinite clay particles, to form stable Si-O-Si bonds upon contact with the kaolinite clay plates, and/or self-polymerization to produce a barrier at the kaolinite clay surface or within the kaolinite clay matrix, or combinations thereof. The reaction scheme for an exemplary scale imbibition promoter is shown below in Eq. 1.

One postulated mechanism of fixation, wherein the kaolinite plates are fixed together at exposed hydroxyl sites, for example, is shown below in Eq. 2.

Kaolinite plates

OH OH OH OH OH OH H ₂ O Kaolinite plates

R — Si-O — Si-O — Si-R ) •HH OH OH OH OH OH R — Sii — O — S Ii-O — S Ii-R Eq. 2

OH OH OH OH OH OH

Kaolinite plates Kaolinite plates

However, as indicated above, there are several postulated mechanisms by which the fixation agents of the present disclosure may interact with fines to reduce fine migration. Thus, no limitation on the scope of the present invention is intended by the specifics of the mechanism mentioned above.

[0013] Selection of the scale inhibition promoter may depend, in one aspect, on the type of base fluid in which the additive is being used. Thus, when using an oil- based or oleaginous drilling fluid, longer aliphatic hydrocarbon chains may be desirable. When using an aqueous fluid, shorter chains and a polar group, such as 3- amino-propyl-triethoxysilane, may be desired. Further, one of ordinary skill in the art would appreciate that other scale inhibition promoters may be used in accordance with embodiments of the present disclosure. Such scale inhibition promoters may be used, for example, at about 0.1 to 15% by weight of the fluid, which is sufficient for most applications. However, one of ordinary skill in the art would appreciate that in other embodiments, more or less may be used.

[0014] One of ordinary skill in the art will recognize that selection of the scale inhibition promoter may depend on a variety of factors. In particular, the selection of the scale inhibition promoter may be related to the properties of the target formation, the properties of the base fluid being used, the commercial availability of the scale inhibition promoter, and downhole conditions, etc.

[0015] The scale inhibitor component of the treatment fluid can be any known scale inhibitor in the oilfield industry, including, for example, phosphate ester scale inhibitors, such as triethanolamine phosphate and salts thereof, phosphonic acid based scale inhibitors, such as aminomethylenephosphonic acid, 1-hydroxyethyl-

1,1-diphosphonic acid and salts thereof, 2-hydroxyethylamino bismethylenephosphonic acid and salts thereof, phosphonocarboxylic acids, and polymeric polyanionic scale inhibitors.

[0016] The concentration of scale inhibitor effective to inhibit scale formation may vary depending upon the conditions of the formation. Exemplary concentrations comprise from about 0.01 to about 50 wt %, and more preferably from about 1 to about 30 wt % of the treatment fluid.

[0017] The base fluid into which the scale inhibition promoter and scale inhibitor may be added may generally be any oleaginous or non-oleaginous (aqueous) fluid phase that is compatible with scale inhibition promoter and scale inhibitor disclosed herein. The base fluid may also comprise the same fluid found in the core being treated with the treatment fluid. Thus, the fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof.

[0018] An oleaginous base fluid may be a liquid, more preferably a natural or synthetic oil, and more preferably the oleaginous base fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including poly alpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof. The concentration of the oleaginous base fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion. In one embodiment, the amount of oleaginous base fluid is from about 30% to about 95% by volume and more preferably about 40% to about 90% by volume of the invert emulsion fluid. The oleaginous base fluid, in one embodiment, may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.

[0019] A non-oleaginous base fluid may preferably be selected from aqueous solutions including fresh water, sea water, a brine containing organic and/or inorganic dissolved salt compounds, liquids containing water-miscible organic compounds, and/or combinations thereof. In one illustrative embodiment, the non- oleaginous base fluid may be a brine solution including inorganic salts such as

calcium halide salts, zinc halide salts, alkali metal halide salts, and the like. In another embodiment, the non-oleaginous base fluid may include an alkali formate such as potassium formate. If an invert emulsion is being formed, the amount of non-oleaginous fluid used is typically less than the theoretical limit needed for forming an invert emulsion. Thus, in one embodiment, the amount of non- oleaginous fluid is less that about 70% by volume, and preferably from about 1% to about 70% by volume. In another embodiment, the non-oleaginous fluid is preferably from about 5% to about 60% by volume of the invert emulsion fluid. However, in other embodiments, the fluid may be water-based, including no more than a small volume of an oleaginous fluid. Thus, the fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof.

[0020] Thus, one embodiment of the present disclosure may include a method of minimizing the number of squeeze operations needed to inhibit scale formation, involving emplacing a scale inhibition promoter and scale inhibitor into a geologic formation and allowing at least a portion of the scale inhibitor to deposit onto the surface of the geologic formation. As used herein, "deposit" means chemically adsorbing the scale inhibitor to the surface of the formation, or precipitating the scale inhibitor and contacting the precipitated scale inhibitor with the surface of the formation. Such deposition of the scale inhibitor allows for the gradual release and comingling of the scale inhibitor with the produced fluids from the formation matrix. Accordingly, once the scale inhibition promoter and scale inhibitor have been emplaced in the geologic formation and the scale inhibitor has been deposited onto the surface of the geologic formation, production of produced fluids may commence.

[0021] The methods of the present disclosure may include emplacing the scale inhibition promoter and scale inhibitor sequentially, such that the scale inhibition promoter is emplaced in the geologic formation and shut in for a period of time sufficient to permit the scale inhibition promoter to deposit on the surface of the geologic formation, followed by emplacing the scale inhibitor in the geologic formation and shutting in for a period of time sufficient to allow the scale inhibitor to deposit on the surface of the geologic formation. Once these steps are complete, production of produced fluids may be initiated, allowing for at least a portion of the

deposited scale inhibitor to be released into the produce fluids, thereby preventing the formation of scale.

[0022] Alternatively, the methods of the present disclosure may include emplacing the scale inhibition promoter and scale inhibitor concurrently, followed by shutting in the well for a period of time sufficient to permit deposition of the scale inhibitor onto the surface of the geologic formation.

[0023] The methods of the present disclosure may also include methods of treating a geologic formation, including emplacing a treatment fluid into the geologic formation, wherein the treatment fluid comprises a base fluid, a scale inhibition promoter, and a scale inhibitor, and performing a shut-in step for a period of time sufficient to initiate deposition of the scale inhibitor on the geologic formation.

[0024] Wellbore fluids of embodiments of this disclosure may be used in drilling, completion, workover operations, etc. using conventional techniques known in the art. Additionally, one skilled in the art would recognize that such wellbore fluids may be prepared with a large variety of formulations. Specific formulations may depend on the stage in which the fluid is being used, for example, depending on the depth and/or the composition of the formation. The drilling fluids described above may be adapted to provide improved drilling fluids under conditions of high temperature and pressure, such as those encountered in deep wells, where high densities are required. Further, one skilled in the art would also appreciate that other additives known in the art may be added to the drilling fluids of the present disclosure without departing from the scope of the present disclosure.

EXAMPLE

[0025] The following example is submitted for the purpose of illustrating the advantages of the treatment fluid of the present disclosure and for facilitating a better understanding of the present disclosure by those skilled in the art. Thus, the following example is submitted for illustrative purposes only and is not intended to limit the invention in any manner.

[0026] This example is submitted for the purpose of showing the comparative effects of performing a scale squeeze operation with just a scale inhibitor versus performing

the same operation with a scale inhibition promoter and a scale inhibitor. The results of these tests are set forth below. All of the samples tested were subjected to the procedures set forth in detail below.

[0027] Formulations of the treatment fluid were designed and tested after selection of the treatment to be carried out by the treatment fluid based on extensive research on fines migration mechanisms. The testing determined the effectiveness of maintaining the minimum scale inhibitor concentration (MIC) when combining the scale inhibitor with a scale inhibition promoter. The testing further determined the effectiveness of the scale inhibitor when combined with scale inhibition promoter on reservoir core material from Oseberg Sør.

[0028] Core Flood Tests - Middle Tarbert Core

[0029] Incorporation of Kaolinite Fixation Agent during Squeeze Treatment to determine lifetime of Scale Inhibitor

[0030] Compatibility testing was performed using different concentrations of the scale inhibition promoter in 10% scale inhibitor (squeeze application concentration) diluted in synthetic produced water. Under all conditions examined, the product was completely compatible.

[0031] Dynamic testing of the fixation agent and scale inhibitor was performed. This testing is designed to give an indication of the minimum scale inhibitor concentration (MIC) necessary to prevent scale formation in the field. The MIC obtained for the scale inhibitor was 1 ppm. The scale inhibition promoter was added to a brine at different concentrations (from 0.5% to 1.5% wt) and the blank scaling time reassessed. It was observed that the blank scaling time significantly increased over that obtained without the scale inhibition promoter, suggesting that the promoter enhances the scale inhibition properties. Scale inhibitor was added to the solution and the MIC re-determined. This gave a MIC of 1 ppm, the same as that obtained without the scale inhibition promoter, indicating that there was no impairment on inhibitor performance.

[0032] Corefiooding of the combined scale inhibitor and scale inhibition promoter was undertaken, using core material representative of the Middle Tarbert core with similar kaolinite content of 10% wt. In order to assess the effectiveness of the scale

inhibition promoter, all test conditions were kept identical other than that the main treatment of this coreflood contained 1% of the scale inhibition promoter.

[0033] A further objective of the coreflood was to assess if the scale inhibition promoter affected the adsorption characteristics of the scale inhibitor. Any interference in inhibitor adsorption could result in potential shorter squeeze lifetimes in the field. As illustrated in Figure 1, the scale inhibitor maintained the MIC over a much greater post-flush injected pore volume when combined with the scale inhibition promoter, indicating that the potential squeeze lifetimes achievable with the scale inhibition promoters were considerable longer than those with the scale inhibitor alone. With only scale inhibitor (no scale inhibition promoter), the MIC was reached after approximately 175 pore volumes whereas the combination of inhibitor and fixation agent gave approximately 850 pore volumes. It is thus apparent that the scale inhibition promoter enhances scale inhibitor adsorption, and that the benefits of non-formation damage coupled with extended squeeze lifetimes are extremely advantageous for well productivity.

[0034] Advantageously, drilling with wellbore fluids formulated in accordance with embodiments of the present disclosure may provide for the stabilization of kaolinite fines within a formation. Moreover, embodiments of the present disclosure may provide for the minimization of the migration of such fines with hydrocarbon flow as well as the subsequent plugging of pores due to such fines migration, which may result in more efficient rate of hydrocarbon production and an increase in the overall amount of hydrocarbon flow from the formation to the surface.

[0035] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.