[0001] This Application claims priority from U.S. Non- Pro visional Patent Application No. 13/596,598, filed August 28, 2012, entitled "Determining Surface Wetting of Metal with Changing Well Fluids," which is hereby incorporated by reference in its entirety.

TECHNICAL FIELD

[0002] The inventions are in the field of producing crude oil or natural gas from subterranean formations. More specifically, the inventions generally relate to methods and apparatuses for determining surface wetting with changing of well fluids. Applications of the methods and apparatuses include without limitation, for example, the designing of spacer or inverter fluids and the field-operational parameters for wellbore cleanout and fluid separation prior to cementing operations in a well.

BACKGROUND ART

[0003] To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir.

Well Servicin2 and Well Fluids

[0004] Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.

[0005] Drilling is the process of drilling the wellbore. After a portion of the wellbore is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.

[0006] Cementing is a common well operation. For example, hydraulic cement compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cement stabilizes the pipe in the wellbore and prevents undesirable migration of fluids along the annulus between the wellbore and the outside of the casing or liner from one zone along the wellbore to the next. Where the wellbore penetrates into a hydrocarbon-bearing zone of a subterranean formation, the casing can later be perforated to allow fluid communication between the zone and the wellbore. The cemented casing also enables subsequent or remedial separation or isolation of one or more production zones of the wellbore, for example, by using downhole tools such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cement in the perforations. Hydraulic cement compositions can also be utilized in intervention operations, such as in plugging highly permeable zones or fractures in zones that may be producing too much water, plugging cracks or holes in pipe strings, and the like.

[0007] Completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.

[0008] Intervention is any operation carried out on a well during or at the end of its productive life that alters the state of the well or well geometry, provides well diagnostics, or manages the production of the well. Workover can broadly refer to any kind of well intervention that involves invasive techniques, such as wireline, coiled tubing, or snubbing. More specifically, however, workover usually refers to a process of pulling and replacing a completion.

Drilling and Drilling Fluids

[0009] The well is created by drilling a hole into the earth (or seabed) with a drilling rig that rotates a drill string with a drilling bit attached to the downward end. Usually the borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm) in diameter. As upper portions are cased or lined, progressively smaller drilling strings and bits must be used to pass through the uphole casings or liners, which steps the borehole down to progressively smaller diameters.

[0010] While drilling an oil or gas well, a drilling fluid is circulated downhole through a drillpipe to a drill bit at the downhole end, out through the drill bit into the wellbore, and then back uphole to the surface through the annular path between the tubular drillpipe and the borehole. The purpose of the drilling fluid is to maintain hydrostatic pressure in the wellbore, lubricate the drill string, and carry rock cuttings out from the wellbore.

[0011] The drilling fluid can be water-based or oil-based. Oil-based fluids tend to have better lubricating properties than water-based fluids, nevertheless, other factors can mitigate in favor of using a water-based drilling fluid. Such factors may include but not limited to presence of water- swellable formations, need for a thin but a strong and impermeable filtercake, temperature stability, corrosion resistance, stuck pipe prevention, contamination resistance and production protection.

Cementing and Hydraulic Cement Compositions

[0012] Hydraulic cement is a material that when mixed with water hardens or sets over time because of a chemical reaction with the water. The cement composition sets by a hydration process, passing through a gel phase to solid phase. Because this is a chemical reaction with water, hydraulic cement is capable of setting even under water.

[0013] The hydraulic cement, water, and any other components are mixed to form a hydraulic cement composition in fluid form. The hydraulic cement composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cement composition is pumped into the annular space between the exterior surfaces of a pipe string and the borehole (that is, the wall of the wellbore). The hydraulic cement composition should be a fluid for a sufficient time before setting to allow for pumping the composition into the wellbore and for placement in a desired downhole location in the well. The cement composition is allowed time to set in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement. The hardened cement supports and positions the pipe string in the wellbore and fills the annular space between the exterior surfaces of the pipe string and the borehole of the wellbore.

Wettability and Wetting of Solid Surfaces

[0014] The wettability of a solid surface or a film on a solid surface can impact various well applications. For example, an oleaginous film on a metal surface of a tubular or a rock material of a subterranean formation can affect bonding of hydraulic cement to the surface. The wettability of rock or the wetting of the rock can affect the flow of a fluid through the matrix of rock of a subterranean formation.

[0015] Wettability involves the contact between a liquid and a solid surface, resulting from the intermolecular interactions when the two different phases are brought together. In general, the degree of wetting (wettability) is depends on a force balance between adhesive forces between the liquid and solid surface and cohesive forces of the liquid (i.e., surface tensions). Adhesive forces between a liquid and solid cause a liquid drop to spread across the surface. Cohesive forces within the liquid cause the drop to ball up and avoid contact with the surface.

[0016] A measurement of the degree of wettability is the contact angle, the angle at which the liquid interface meets the dry solid interface. If the wettability is very favorable to the liquid, the contact angle will be low, and the fluid will spread to cover or "wet" a larger area of the solid surface. If the wettability is unfavorable, the contact angle will be high, and the fluid will form a compact, self-contained droplet on the solid surface. If the contact angle of a water droplet on a solid surface is less than 90°, the surface may be said to be "water-wettable" (and inverse proportionally, probably not oil-wettable); whereas if the contact angle of an oil droplet on a solid surface is less than 90°, the surface may be said to be "oil-wettable" (and inverse proportionally, not water-wettable. The surfaces of some materials are both water wettable and oil wettable.

Table 1

[0017] As used herein, a wet or wetted surface or the wetting of a surface may refer to a liquid phase that is directly in contact with and adhered to the surface of a solid body. For example, the liquid phase can be an oleaginous film on the surface of a metallic tubular or the face of a borehole in the material of a subterranean formation.

[0018] Some well fluids can form such a film or layer on a downhole surface, which can have undesirable effects. The fluid (or a liquid component of the fluid) can form a film or layer on the surface, which can act as a physical barrier between the material of the underlying solid body and a fluid adjacent to the surface of the solid body. In effect, such a film presents a different wettability characteristic than the material of the underlying solid body. For example, an oleaginous film on the surface of a metal tubular blocks water from wetting the underlying surface, which would otherwise be water- wettable.

[0019] A metallic surface of a downhole tubular is typically both water wettable and oil wettable. If first wetted with an oleaginous film, however, the oleaginous film on the metallic surface blocks the metal surface from being wettable with a water-based fluid.

Wetting of Tubulars and Formation Surfaces for Cementing

[0020] Hydraulic cement compositions do not bond well to oil-wetted surfaces. After drilling a wellbore with an oil-based drilling mud, the surfaces of tubulars and the formation in the wellbore may become oil-wetted with an oleaginous film. It is necessary to remove the film on the solid surface of the tubular from being oil-wetted with such a film to improve cement bonding.

[0021] In a case where complete surface wetting with water is not achieved prior to placing cement in the desired zone of interest, only partial bonding of the surfaces with cement is obtained. Because of this incomplete surface bonding, there is a proportional decrease in the shear bond strength of the interface between the set cement sheath and the formation/tubular surfaces and premature interfacial de-bonding might occur under the loads experienced during the course of the well operations. This may have unwanted consequences such as interzonal communication, loss of production, and sustained casing pressure. Any of these can be detrimental to the safety and economics of hydrocarbon production from the well.

Significance of Interfacial Phenomena

[0022] Physical, chemical, and electrical properties of matter confined to phase boundaries are often profoundly different from those of the same matter in bulk. For many systems, although multiphase, the fraction of total mass localized at the phase boundaries is small that the contribution of such boundary properties to the general system properties is negligible.

[0023] However, many important systems exist under which these properties play significant role. For example, such systems include dispersions in liquids, which can be of solids (e.g., sols, suspensions, or slurries) or of other liquids (e.g., emulsions). In dispersions, the phase boundary area is so large relative to the volume of the system that a substantial fraction of the total mass of the system is present at the boundaries. Surfactants (also known as surface-active agents) play a major role in these systems.

[0024] Another such system is where the phenomena occurring at the phase boundaries are so different from the bulk phases that the behavior of the system is substantially determined by phase-boundary processes. Examples include detergency, floatation, and cleanout.

[0025] It is necessary to understand the causes of the behavior of matter at the phase-interfaces and the variables that affect this behavior in order to predict and control the properties of systems in which phase-boundary properties play a significant role. In addition, as temperature, pressure, shear, and other conditions vary, these properties used to quantify

interfacial phenomena will also change. The systems of well fluids and operations with well fluids can be highly complex and difficult to predict.

[0026] It would be highly desirable in well operations to have methods for determining wettability and improving operating conditions and contact times for well fluids. Applications include, for example, the designing of spacer or inverter fluids and determining the field-operational parameters for wellbore cleanout and fluid separation prior to cementing operations in a well.

SUMMARY OF THE INVENTION

[0027] According to the invention, methods and apparatuses are provided for determining surface wetting with changing of well fluids. In general, the methods according to the invention include measuring electrical impedance spectroscopy ("EIS") for a system simulating downhole conditions for the wetting of a surface. Methods and apparatuses for making EIS measurements model double-layer capacitance at a downhole surface in a well under the conditions in the well, from which the nature and quantification of the wetting of the surface for such conditions can be inferred.

[0028] In addition, methods are provided for making EIS measurements downhole in a well to measure surface wetting directly in the downhole environment and conditions.

[0029] These and other aspects of the invention will be apparent to one skilled in the art upon reading the following detailed description. While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof will be described in detail and shown by way of example. It should be understood, however, that it is not intended to limit the invention to the particular forms disclosed, but, on the contrary, the invention is to cover all modifications and alternatives falling within the spirit and scope of the invention as expressed in the appended claims.

BRIEF DESCRIPTION OF THE DRAWING

[0030] The accompanying drawing is incorporated into the specification to help illustrate examples according to the presently most-preferred embodiment of the invention. [0031] Figures la, lb, and lc are illustrations of a sequence of fluid displacement in a wellbore during a cementing operation. The spacer fluid is illustrated being pumped into a wellbore of a well penetrating a formation 10 and down through a casing (which has not yet been cemented) and then out the lower end of the casing and up through the annulus between the outside of the casing and the borehole of the wellbore. Figure la illustrates a drilling mud initially the annulus of the wellbore around the casing. Figure lb illustrates a spacer fluid being pumped through the casing to displace the drilling mud from the annulus. Figure lc illustrates a cement composition (sometimes referred to as a cement slurry) being pumped through the casing to displace the spacer fluid and placed in the annulus for cementing the casing in the wellbore. To seal the annulus with cement requires good cement bonding between both the outer wall of the casing and the rock of the subterranean formation of the borehole.

[0032] Figure 2 is an illustration modeling fluid intermixing between a prior drilling mud in a wellbore and a spacer fluid as the spacer fluid displaces the prior well fluid, which is similar to the stage illustrated in Figure lb. In Figure 2, the spacer fluid is illustrated being pumped into the well and down through a casing (which has not yet been cemented) and then out the lower end of the casing and up through the annulus between the outside of the casing and the borehole of the wellbore. As the spacer fluid displaces the prior fluid in the wellbore, there is a diffused layer of mixing and channeling between the prior fluid and the spacer fluid. The diffused layer includes varying mixtures of the prior fluid in the well and spacer fluid. Such a diffused layer is sometimes referred to as contaminated spacer fluid. The spacer fluid being pumped behind the diffused layer is sometimes referred to as pure or uncontaminated spacer fluid.

[0033] Figure 3 is a graphical representation of a diffused layer between an oil-based drilling mud and a water-based spacer fluid, wherein at some degree of mixing and depending on the particular compositions of the oil-based and water-based fluids, the continuous phase of the fluid in the zone of the well inverts from oil-based to water-based.

[0034] Figure 4 illustrates the formation of an electrical double layer at the interface between a positively charged surface and a bulk liquid including electrolyte ions, without any intervening film of an oleaginous liquid phase on the positively charged surface. [0035] Figure 5 is a graphical illustration of electric potential distribution of an electrical double layer as a function of the dielectric dipole moment (i.e., Debye length) of the molecules of a liquid phase, including showing the region of the slipping plane.

[0036] Figure 6a is a vertical cross-sectional view of an electrical apparatus for measuring the change in surface wetting on a metal surface, which can be selected, for example, to simulate a metal surface in a well. The electrical circuit for measuring electrical impedance between the electrodes of the apparatus is not shown in detail. Figure 6b is a top view of the apparatus in Figure 6a, illustrating the insulated separation of the electrodes in the container wall of the apparatus. This type of apparatus can measure the change in surface wetting on an electrode surface from a first liquid phase to a second liquid phase as a second bulk fluid including the second liquid phase is sheared in the container of the apparatus at a controlled rate for a controlled contact time. The electrode surfaces can simulate the metallic body of a tubular. The first liquid phase can simulate a prior oleaginous film formed on the surface. The second bulk fluid can and conditions of shear and time can simulate the displacement of the oleaginous film by a spacer fluid.

[0037] Figure 7a is a vertical cross-sectional view of an electrical apparatus for measuring the change in surface wetting on a dielectric solid surface, which can be selected, for example, to simulate a rock surface of a subterranean formation. The electrical circuit for measuring electrical impedance between the electrodes of the apparatus is not shown in detail. Figure 7b is a top view of the apparatus in Figure 7a, illustrating the insulated separation of the dielectric surfaces in the container wall of the apparatus. It should be understood, of course, that the dielectric constant of the insulating material of the container should be lower than that of any liquid phases being tested for wetting on the testing surface. Similarly, it should be understood, of course, that the dielectric constant of the insulating material of the container should be lower than that of the material of the testing surface. A first electrode is placed in electrical contact with the dielectric solid to be tested. This type of apparatus can measure the change in surface wetting on a tested dielectric surface from a first liquid phase to a second liquid phase as a second bulk fluid including the second liquid phase is sheared in the container of the apparatus at a controlled rate for a controlled contact time. The dielectric solid surfaces can be selected to simulate the rock of a subterranean formation in a well. The first liquid phase can simulate a prior oleaginous film formed on the surface of the rock. The second bulk fluid can and conditions of shear and time can simulate the displacement of the oleaginous film by a spacer fluid.

[0038] Figure 8 is a vertical cross-sectional view of an alternative electrical apparatus for measuring the change in surface wetting on a dielectric solid surface, which can be selected, for example, to simulate a rock surface of a subterranean formation. As illustrated in Figure 8, in this embodiment the rock surface is axially separated from another electrode exposed to a bulk fluid in the chamber of the container. It should be understood, of course, that the dielectric constant of the insulating material of the container should be higher than that of any liquid phases being tested for wetting on the testing surface. This type of apparatus can measure the change in surface wetting on a tested dielectric surface from a first liquid phase to a second liquid phase as a second bulk fluid including the second liquid phase is sheared in the container of the apparatus at a controlled rate for a controlled contact time. The dielectric solid surfaces can be selected to simulate the rock of a subterranean formation in a well. The first liquid phase can simulate a prior oleaginous film formed on the surface of the rock. The second bulk fluid can and conditions of shear and time can simulate the displacement of the oleaginous film by a spacer fluid.

[0039] Figures 9a and 9b are vertical cross-sectional views illustrating an embodiment depicting direct electrical measurements in a well, which can be used, for example, during the real-time pumping operations to determine any change in wetting of a downhole tubular surface during a well operation such as cementing. Figure 9a is a vertical cross-sectional view of a portion of a metallic tubular, such as a casing, positioned in a wellbore. Figure 9b is a detail view of a test probe device associated with a portion of the casing in the wellbore.

[0040] Figure 10 is a graphical illustration representing voltage (V) and current (I) waveforms in time (t) in a pseudo-linear system, for which the current response to a sinusoidal potential will be a similar sinusoidal signal at the same frequency, but with a lag in phase.

[0041] Figure 11 illustrates an example of a circuit that can be used for impedance modeling in electrical systems. Figure 11 is similar to the type of circuit known as a Failed Paint Model (FP) circuit model.

[0042] Figure 12 illustrates an example of a circuit that can be used for impedance modeling in electrical systems. Figure 12 is similar to the type of circuit known as a Failed Paint Model with Diffusion ("CPED") circuit model.

[0043] Figure 13 shows an example of Nyquist plot comparing the impedance data before and after surface wetting with a Failed Paint Model (FP) circuit model as in Figure 11.

[0044] Figure 14 shows an example of a Bode plot comparing the impedance data before and after surface wetting with a Failed Paint Model (FP) circuit model as in Figure 11.

[0045] Figure 15 shows an example of a Nyquist plot comparing the impedance data before and after surface wetting using a Constant Phase Element with Diffusion ("CPED") circuit model as in Figure 12.

[0046] Figure 16 shows an example of a Nyquist plot from Electrical Impedance Spectroscopy under a no shear condition for different percentage extents of non-aqueous liquid phase coverage, where the non-aqueous film used is an Oil Based Mud ("OBM") made with mineral oil and the electrolyte used is a water-based inverter fluid.

[0047] Figure 17 shows an example of a Bode plot of impedance vs. frequency, before and after surface wetting using a Constant Phase Element with Diffusion ("CPED") circuit model as in Figure 12.

[0048] Figure 18 shows a Bode magnitude plot from Electrical Impedance Spectroscopy for different extents of non-aqueous film coverage corresponding to the Nyquist plot in Figure 16.

[0049] Figure 19 is a graph of double layer capacitance vs. non-oil-wetting film coverage for a grease and salt-water combination.

[0050] Figure 20 is a graph of double layer capacitance vs. non-oil-wetting film coverage for OBM and salt-water combination.

[0051] Figure 21 is a graph of inferred double-layer capacitance vs. percent coverage of several different combinations of non-aqueous films in water-based bulk fluids from electrical measurements in an electrical cell using an identical first electrode and second electrode.

[0052] Figure 22 shows Bode magnitude plots at different durations of shear for the measuring of the effect of contact time with 0.05 gal/bbl surfactant concentration in an aqueous bulk spacer fluid, where the surfactant is an equiproportional mixture of surfactants including alcohol ether sulfate, a low hydrolipic balance non-ionic nonylphenol, and a high hydrolipic balance non- ionic nonylphenol, after following the steps of: (1) placing a spacer fluid in the test cell and taking EIS measurement; (2) starting from a state where the electrodes are coated with non-aqueous film and the test cell is filled with the spacer fluid at no shear and taking EIS measurements; and (3) shear is applied by rotating a cylindrical bob at 900 RPM in a configuration similar to as shown in Figures 6a and 6b and EIS data is recorded at intermittent times of 1 minute increments from 1 minute to 7 minutes.

[0053] Figure 23 shows Bode magnitude plots for the experiment in Figure 22 repeated with 0.1 gal/bbl surfactant concentration.

[0054] Figure 24 shows Bode magnitude plots for Experiment in Figure 22 repeated with 0.2 gal/bbl surfactant concentration, at intermittent times of 1 -minute increments from 1 minute to 3 minutes.

[0055] Figure 25 shows experimental Bode magnitude plots showing the effect of shear rates after following the steps of: (1) placing pure spacer fluid in the test cell and taking EIS measurement; (2) starting from a state where the electrodes are coated with non-aqueous film and the test cell is filled with the spacer fluid at no shear and taking EIS measurements; and (3) shear is applied by rotating a cylindrical bob for 60 seconds at different RPMs of 900 RPM, 1200 RPM, and 1250 RPM in a configuration similar to the apparatus illustrated in Figures 6a and 6b and EIS data is recorded at 1 minute.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS

AND BEST MODE

Definitions and Usages

Interpretation

[0056] The words or terms used herein have their plain, ordinary meaning in the field of this disclosure, except to the extent explicitly and clearly defined in this disclosure or unless the specific context otherwise requires a different meaning.

[0057] If there is any conflict in the usages of a word or term in this disclosure and one or more patent(s) or other documents that may be incorporated by reference, the definitions that are consistent with this specification should be adopted.

[0058] The words "comprising," "containing," "including," "having," and all grammatical variations thereof are intended to have an open, non-limiting meaning. For example, a composition comprising a component does not exclude it from having additional components, an apparatus comprising a part does not exclude it from having additional parts, and a method having a step does not exclude it having additional steps. When such terms are used, the compositions, apparatuses, and methods that "consist essentially of or "consist of the specified components, parts, and steps are specifically included and disclosed.

[0059] The control or controlling of a condition includes any one or more of maintaining, applying, or varying of the condition. For example, controlling the temperature of a substance can include maintaining an initial temperature, heating, or cooling.

[0060] The indefinite articles "a" or "an" mean one or more than one of the component, part, or step that the article introduces.

[0061] Whenever a numerical range of degree or measurement with a lower limit and an upper limit is disclosed, any number and any range falling within the range is also intended to be specifically disclosed. For example, every range of values (in the form "from a to b," or "from about a to about b," or "from about a to b," "from approximately a to b," and any similar expressions, where "a" and "b" represent numerical values of degree or measurement) is to be understood to set forth every number and range encompassed within the broader range of values.

[0062] Terms such as "first," "second," "third," etc. are assigned arbitrarily and are merely intended to differentiate between two or more components, parts, or steps that are otherwise similar or corresponding in nature, structure, function, or action. For example, the words "first" and "second" serve no other purpose and are not part of the name or description of the following name or descriptive terms. The mere use of the term "first" does not require that there be any "second" similar or corresponding component, part, or step. Similarly, the mere use of the word "second" does not require that there by any "first" or "third" similar or corresponding component, part, or step. Further, it is to be understood that the mere use of the term "first" does not require that the element or step be the very first in any sequence, but merely that it is at least one of the elements or steps. Similarly, the mere use of the terms "first" and "second" does not necessarily require any sequence. Accordingly, the mere use of such terms does not exclude intervening elements or steps between the "first" and "second" elements or steps, etc.

Well Terms

[0063] In the context of production from a well, oil and gas are understood to refer to crude oil and natural gas. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.

[0064] A "subterranean formation" is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it.

[0065] In geology, rock or stone is a naturally occurring solid aggregate of minerals or mineraloids. The Earth's outer solid layer, the lithosphere, is made of rock. Three majors groups of rocks are defined: igneous, sedimentary, and metamorphic.

[0066] A subterranean formation having a sufficient porosity and permeability to store and transmit fluids is sometimes referred to as a "reservoir." The vast majority of reservoir rocks are sedimentary rocks, but highly fractured igneous and metamorphic rocks sometimes contain substantial reservoirs as well.

[0067] A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.

[0068] A "well" includes a wellhead and at least one wellbore from the wellhead penetrating the earth. The "wellhead" is the surface termination of a wellbore, which surface may be on land or on a seabed. A "well site" is the geographical location of a wellhead of a well. It may include related facilities, such as a tank battery, separators, compressor stations, heating or other equipment, and fluid pits. If offshore, a well site can include a platform.

[0069] The "wellbore" refers to the drilled hole, including any cased or uncased portions of the well or any other tubulars in the well. The "borehole" usually refers to the inside wellbore wall, that is, the rock surface or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. As used herein, "uphole," "downhole," and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.

[0070] A wellbore can be used as a production or injection wellbore. A production wellbore is used to produce hydrocarbons from the reservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.

[0071] As used herein, introducing "into a well" means introduced at least into and through the wellhead. According to various techniques known in the art, tubulars, equipment, tools, or well fluids can be directed from the wellhead into any desired portion of the wellbore.

[0072] As used herein, the word "tubular" means any kind of body in the form of a tube. Examples of tubulars include, but are not limited to, a drill pipe, a casing, a tubing string, a line pipe, and a transportation pipe. Tubulars can also be used to transport fluids into or out of a subterranean formation, such as oil, gas, water, liquefied methane, coolants, and heated fluids. For example, a tubular can be placed underground to transport produced hydrocarbons or water from a subterranean formation to another location.

[0073] As used herein, the term "annulus" means the space between two generally cylindrical objects, one inside the other. The objects can be concentric or eccentric. Without limitation, one of the objects can be a tubular and the other object can be an enclosed conduit. The enclosed conduit can be a wellbore or borehole or it can be another tubular. The following are some non-limiting examples illustrate some situations in which an annulus can exist. Referring to an oil, gas, or water well, in an open hole well, the space between the

outside of a tubing string and the borehole of the wellbore is an annulus. In a cased hole, the space between the outside of the casing the borehole is an annulus. In addition, in a cased hole there may be an annulus between the outside cylindrical portion of a tubular such as a production tubing string and the inside cylindrical portion of the casing. An annulus can be a space through which a fluid can flow or it can be filled with a material or object that blocks fluid flow, such as a packing element. Unless otherwise clear from the context, as used herein an annulus is a space through which a fluid can flow.

[0074] As used herein, a "well fluid" broadly refers to any fluid adapted to be introduced into a well for any purpose. A well fluid can be, for example, a drilling fluid, a cement composition, a treatment fluid, or a spacer fluid. If a well fluid is to be used in a relatively small volume, for example less than about 200 barrels (32 m3), it is sometimes referred to as a wash, dump, slug, or pill.

[0075] Drilling fluids, also known as drilling muds or simply "muds," are typically classified according to their base fluid (that is, the continuous phase). A water-based mud ("WBM") has solid particulate (e.g., clays, bulk density increasing agents, lost circulation materials,) suspended in an aqueous liquid as the continuous phase. The water can be brine. A brine -based drilling fluid is a water-based mud in which the aqueous component is brine. In some cases, oil may be emulsified in a water-based drilling mud. An oil-based mud ("OBM") has solid particulate suspended in oil as the continuous phase. In some cases, an aqueous phase of water or brine is emulsified in the oil. Drill Cuttings from the formation will be the additional solid particulates getting suspended in both oil-based and water based muds as the drilling process begins.

[0076] As used herein, the word "treatment" refers to any treatment for changing a condition of any portion of a wellbore or an adjacent subterranean formation; however, the word "treatment" does not necessarily imply any particular treatment purpose. A treatment usually involves introducing a well fluid for the treatment, in which case it may be referred to as a treatment fluid, into a well. As used herein, a "treatment fluid" is a fluid used in a treatment. The word "treatment" in the term "treatment fluid" does not necessarily imply any particular treatment or action by the fluid.

[0077] As used herein, the terms spacer fluid, wash fluid, and inverter fluid can be used interchangeably. A spacer fluid is a fluid used to physically separate one special-purpose fluid from another. It may be undesirable for one special-purpose fluid to mix with another used in the well, so a spacer fluid compatible with each is used between the two. A spacer fluid is usually used when changing between well fluids used in a well.

[0078] For example, a spacer fluid is used to change from a drilling fluid during drilling to cement composition during cementing operations in the well. In case of an oil-based drilling fluid, it should be kept separate from a water-based cementing fluid. In changing to the latter fluid, a chemically treated water-based spacer fluid is usually used to separate the drilling fluid from the water-based cementing fluid.

[0079] A spacer fluid specially designed to separate a special purpose oil-external fluid from a special purpose water-external fluid may be termed as an inverter fluid. Inverter fluids may be so designed that the diffused contaminated layer between both the special purpose fluids has progressive variation in properties like solids carrying capability, electrical conductivity, rheology, and chemical potential. In other words, inverter fluids may be ideally designed to be fully compatible physically and chemically with either or both of the special purpose fluids under the simulated conditions of pressure, temperature and shear. Compatibility may be warranted by rheological investigations or visual observations at all intermediate compositions. Unwanted flocculation, coagulation, or excessive thinning of the admixture compared to the original fluids is typically considered to be a signature for incompatibility.

[0080] In the context of cementing, compatibility can be determined by monitoring viscosity upon mixing. For compatibility, the viscosity of any mixture of two well fluids should be between the viscosity of either fluid. For example, the viscosity of an oil-based drilling mud may be, for example, about 100 cP. The viscosity of a spacer fluid may be, for example, about 200 cP. These two well fluids would be considered compatible if the viscosity of any mixture of the two fluids is in the range of about 100 cP to about 200 cP; but if outside this viscosity range, then a high degree of fingering, channeling, gelling, settling, separating, etc. would be likely to occur on mixing the two fluids. The proper selection of well fluids must be used for a successful cementing operation.

[0081] Volumes of spacer fluid that are consumed in channel lengths due to contamination process are not sufficient to clean wellbore surfaces or change wetting of a

surface. These volumes should be considered sacrificial and the amount of pure uncontaminated spacer is estimated from surface wetting techniques.

[0082] A zone refers to an interval of rock along a wellbore that is differentiated from uphole and downhole zones based on hydrocarbon content or other features, such as permeability, composition, perforations or other fluid communication with the wellbore, faults, or fractures. A zone of a wellbore that penetrates a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a "production zone." A "treatment zone" refers to an interval of rock along a wellbore into which a well fluid is directed to flow from the wellbore. As used herein, "into a treatment zone" means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.

[0083] As used herein, a downhole fluid is an in-situ fluid in a well, which may be the same as a well fluid at the time it is introduced, or a well fluid mixed with another fluid downhole, or a fluid in which chemical reactions are occurring or have occurred in-situ downhole.

[0084] Generally, the greater the depth of the formation, the higher the static temperature and pressure of the formation. Initially, the static pressure equals the initial pressure in the formation before production. After production begins, the static pressure approaches the average reservoir pressure.

[0085] A "design" refers to the estimate or measure of one or more parameters planned or expected for a particular stage of a well service or associated well fluid. For example, a fluid can be designed to have components that provide a minimum viscosity for at least a specified time under expected downhole conditions. A well service may include design parameters such as fluid volume to be pumped, required pumping time for a treatment, or the shear conditions of the pumping, and contact time of a treatment fluid with a zone of interest.

[0086] The term "design temperature" refers to an estimate or measurement of the actual temperature at the downhole environment at the time of a well treatment. That is, design temperature takes into account not only the bottom hole static temperature ("BHST"), but also the effect of the temperature of the well fluid on the BHST during treatment. The design temperature is sometimes referred to as the bottom hole circulation temperature ("BHCT"). Because treatment fluids may be considerably cooler than BHST, the difference

between the two temperatures can be quite large. Ultimately, if left undisturbed, a subterranean formation will return to the BHST.

Substances and Chemicals

[0087] A substance can be a pure chemical or a mixture of two or more different chemicals.

[0088] A pure chemical is a sample of matter that cannot be separated into simpler components without chemical change. A chemical element is composed of atoms with identical atomic number. A chemical compound is formed from different elements chemically combined in definite proportions by mass.

[0089] An atom or molecule is the smallest particle of a chemical that retains the chemical properties of the element or compound. A molecule is two or more chemically bound atoms with characteristic composition and structure. Making or breaking bonds in a molecule changes it to a different chemical.

[0090] An ionic compound is made of distinguishable ions, including at least one cation (a positively charged ion) and at least one anion (a negatively charged ion), held together by electrostatic forces. An ion is an atom or molecule that has acquired a charge by either gaining or losing electrons. An ion can be a single atom or molecular. An ion can be separated from an ionic compound, for example, by dissolving the ions of the compound in a polar solvent.

Physical States, Phases, and Materials

[0091] As used herein, "phase" is used to refer to a substance having a chemical composition and physical state that is distinguishable from an adjacent phase of a substance having a different chemical composition or a different physical state.

[0092] The word "material" is often used as a synonym for a single phase of a bulk scale (larger than a particle), although it can sometimes mean a bulk scale of a mixture of phases, depending on the context.

[0093] As used herein, if not other otherwise specifically stated, the physical state or phase of a substance (or mixture of substances) and other physical properties are determined at a temperature of 77 °F (25 °C) and a pressure of 1 atmosphere (Standard Laboratory Conditions) without applied shear.

Continuum Mechanics and Rheology

[0094] One of the purposes of identifying the physical state or phase of a substance and measuring viscosity or other physical characteristics of a fluid is to establish whether it is pumpable. In the context of oil and gas production, the pumpability of a fluid is with particular reference to the ranges of physical conditions that may be encountered at a wellhead and with the types and sizes of pumps available to be used for pumping fluids into a well. Another purpose is to determine what the physical state of the substance and its physical properties will be during pumping through a wellbore and under other downhole conditions in the well, including over time and changing temperatures, pressures, and shear rates.

[0095] Continuum mechanics is a branch of mechanics that deals with the analysis of the kinematics and the mechanical behavior of materials modeled as a continuous mass on a large scale rather than as distinct particles. Fluid mechanics is a branch of continuum mechanics that studies the physics of continuous materials that take the shape of their container. Rheology is the study of the flow of matter: primarily in the liquid state, but also as "soft solids" or solids under conditions in which they respond with plastic flow rather than deforming elastically in response to an applied force. It applies to substances that have a complex structure, such as fluid suspensions, gels, etc. The flow of such substances cannot be fully characterized by a single value of viscosity, which varies with temperature, pressure, and other factors. For example, ketchup can have its viscosity reduced by shaking (or other forms of mechanical agitation) but water cannot.

Particles, Particulates, Aggregates, and Fibers

[0096] As used herein, a "particle" refers to a body having a finite mass and sufficient cohesion such that it can be considered as an entity but having relatively small dimensions. A particle can be of any size ranging from molecular scale to macroscopic, depending on context.

[0097] A particle can be in any physical state. For example, a particle of a substance in a solid state can be as small as a few molecules on the scale of nanometers up to a large particle on the scale of a few millimeters, such as large grains of sand. Similarly, a particle of a substance in a liquid state can be as small as a few molecules on the scale of nanometers or a large drop on the scale of a few millimeters.

[0098] As used herein, "particulate" or "particulate material" refers to matter in the physical form of distinct particles in a solid or liquid state (which means such an association of a few atoms or molecules). A particulate is a grouping of particles based on common characteristics, including chemical composition and particle size range, particle size distribution, or median particle size. As used herein, a particulate is a grouping of particles having similar chemical composition and particle size ranges anywhere in the range of about 1 micrometer (e.g., microscopic clay or silt particles) to about 3 millimeters (e.g., large grains of sand).

[0099] As used herein, a particle can be an aggregate or a composite of different solid phases bound together.

[0100] It should be understood that the terms "particle" and "particulate," includes all known shapes of particles including substantially rounded, spherical, oblong, ellipsoid, rod- like, fiber, polyhedral (such as cubic materials), etc., and mixtures thereof. For example, the term "particulate" as used herein is intended to include solid particles having the physical shape of platelets, shavings, flakes, ribbons, rods, strips, spheroids, toroids, pellets, tablets or any other physical shape.

[0101] As used herein, a fiber is a particle or grouping of particles having an aspect ratio L/D greater than 5/1.

Dispersions

[0102] A dispersion is a system in which particles of a substance of one chemical composition and physical state are dispersed in another substance of a different chemical composition or physical state. If a substance has more than one phase, the most external phase is referred to as the continuous phase of the substance as a whole, regardless of the number of different internal phases or nested phases.

[0103] A dispersion can be classified a number of different ways, including based on the size of the dispersed particles, the uniformity or lack of uniformity of the dispersion, and, if a fluid, whether or not precipitation occurs.

Classification of Dispersions: Heterogeneous and Homogeneous

[0104] A dispersion is considered to be heterogeneous if the dispersed particles are not dissolved and are greater than about 1 nanometer in size. (For reference, the diameter of a molecule of toluene is about 1 nm).

[0105] Heterogeneous dispersions can have gas, liquid, or solid as an external phase. For example, in a case where the dispersed-phase particles are liquid in an external phase that is another liquid, this kind of heterogeneous dispersion is more particularly referred to as an emulsion. A solid dispersed phase in a continuous liquid phase is referred to as a sol, suspension, or slurry, partly depending on the size of the dispersed solid particulate.

[0106] A dispersion is considered to be homogeneous if the dispersed particles are dissolved in solution or the particles are less than about 1 nanometer in size. Even if not dissolved, a dispersion is considered to be homogeneous if the dispersed particles are less than about 1 nanometer in size.

Classification of Heterogeneous Dispersions: Suspensions and Colloids

[0107] Heterogeneous dispersions can be further classified based on the dispersed particle size.

[0108] A heterogeneous dispersion is a "suspension" where the dispersed particles are larger than about 50 micrometer. Such particles can be seen with a microscope, or if larger than about 50 micrometers (0.05 mm), with the unaided human eye. The dispersed particles of a suspension in a liquid external phase may eventually separate on standing, e.g., settle in cases where the particles have a higher density than the liquid phase. Suspensions having a liquid external phase are essentially unstable from a thermodynamic point of view; however, they can be kinetically stable over a long period depending on temperature and other conditions.

[0109] A heterogeneous dispersion is a "colloid" where the dispersed particles range up to about 50 micrometer (50,000 nanometers) in size. The dispersed particles of a colloid are so small that they settle extremely slowly, if ever. In some cases, a colloid can be considered as a homogeneous mixture. This is because the distinction between "dissolved"

and "particulate" matter can be sometimes a matter of approach, which affects whether or not it is homogeneous or heterogeneous.

Classification of Homogeneous Dispersions: Solutions

[0110] A solution is a special type of homogeneous mixture. A solution is considered homogeneous: (a) because the ratio of solute to solvent is the same throughout the solution; and (b) because solute will never settle out of solution, even under powerful centrifugation, which is due to intermolecular attraction between the solvent and the solute. An aqueous solution, for example, saltwater, is a homogenous solution in which water is the solvent and salt is the solute.

[0111] One may also refer to the solvated state, in which a solute ion or molecule is complexed by solvent molecules. A chemical that is dissolved in solution is in a solvated state. The solvated state is distinct from dissolution and solubility. Dissolution is a kinetic process, and is quantified by its rate. Solubility quantifies the concentration of the solute at which there is dynamic equilibrium between the rate of dissolution and the rate of precipitation of the solute. Dissolution and solubility can be dependent on temperature and pressure, and may be dependent on other factors, such as salinity or pH of an aqueous phase.

Solubility Terms

[0112] A substance is considered to be "soluble" in a liquid if at least 10 grams of the substance can be dissolved in one liter of the liquid when tested at 77 °F and 1 atmosphere pressure for 2 hours and considered to be "insoluble" if less soluble than this.

[0113] As will be appreciated by a person of skill in the art, the hydratability, dispersibility, or solubility of a substance in water can be dependent on the salinity, pH, or other substances in the water. Accordingly, the salinity, pH, and additive selection of the water can be modified to facilitate the hydratability, dispersibility, or solubility of a substance in aqueous solution. To the extent not specified, the hydratability, dispersibility, or solubility of a substance in water is determined in deionized water, at neutral pH, and without any other additives.

[0114] Dielectric constants are not the only measures of polarity but generally, dielectric constant of the material provides a rough measure of the material's polarity. As

used herein, the term "polar" means having a dielectric constant greater than 15. The term "relatively polar" means having a dielectric constant greater than about 5 and less than about 15 "Non-polar" means having a dielectric constant less than 5.

Fluids

[0115] A fluid can be a single phase or a dispersion. In general, a fluid is an amorphous substance that is or has a continuous phase of particles that are smaller than about 1 micrometer that tends to flow and to conform to the outline of its container.

[0116] Examples of fluids are gases and liquids. A gas (in the sense of a physical state) refers to an amorphous substance that has a high tendency to disperse (at the molecular level) and a relatively high compressibility. A liquid refers to an amorphous substance that has little tendency to disperse (at the molecular level) and relatively high incompressibility. The tendency to disperse is related to Intermolecular Forces (also known as van der Waal's Forces). (A continuous mass of a particulate, e.g., a powder or sand, can tend to flow as a fluid depending on many factors such as particle size distribution, particle shape distribution, the proportion and nature of any wetting liquid or other surface coating on the particles, and many other variables. Nevertheless, as used herein, a fluid does not refer to a continuous mass of particulate because the sizes of the solid particles of a mass of a particulate are too large to be appreciably affected by the range of Intermolecular Forces.)

[0117] As used herein, a fluid is a substance that behaves as a fluid under Standard Laboratory Conditions, that is, at 77 °F (25 °C) temperature and 1 atmosphere pressure, and at the higher temperatures and pressures usually occurring in subterranean formations without applied shear.

[0118] Every fluid inherently has at least a continuous phase. A fluid can have more than one phase. The continuous phase of a well fluid is a liquid under Standard Laboratory Conditions. For example, a well fluid can in the form of be a suspension (solid particles dispersed in a liquid phase), an emulsion (liquid particles dispersed in another liquid phase), or a foam (a gas phase dispersed in liquid phase).

[0119] As used herein, a water-based fluid means that water or an aqueous solution is the dominant material of the continuous phase, that is, greater than 50% by weight, of the continuous phase of the substance.

[0120] In contrast, "oil-based" means that oil is the dominant material by weight of the continuous phase of the substance. In this context, the oil of an oil-based fluid can be any oil. In general, an oil is any substance that is liquid Standard Laboratory Conditions, is hydrophobic, and soluble in organic solvents. Oils have a high carbon and hydrogen content and are relatively non-polar substances, for example, having a dielectric constant of 1.5 to 5. This general definition includes classes such as petrochemical oils, vegetable oils, and many organic solvents. All oils can be traced back to organic sources.

Apparent Viscosity of a Fluid

[0121] Viscosity is a measure of the resistance of a fluid to flow. In everyday terms, viscosity is "thickness" or "internal friction." Thus, pure water is "thin," having a relatively low viscosity whereas honey is "thick," having a relatively higher viscosity. Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). More precisely, viscosity is defined as the ratio of shear stress to shear rate.

[0122] A fluid moving along solid boundary will incur a shear stress on that boundary. The no-slip condition dictates that the speed of the fluid at the boundary (relative to the boundary) is zero, but at some distance from the boundary, the flow speed must equal that of the fluid. The region between these two points is named the boundary layer.

[0123] A Newtonian fluid (named after Isaac Newton) is a fluid for which stress versus strain rate curve is linear and passes through the origin. The constant of proportionality is known as the viscosity. Examples of Newtonian fluids include water and most gases. Newton's law of viscosity is an approximation that holds for some substances but not others.

[0124] Non-Newtonian fluids exhibit a more complicated relationship between shear stress and velocity gradient (i.e., shear rate) than simple linearity. Thus, there exist a number of forms of non-Newtonian fluids. Shear thickening fluids have an apparent viscosity that increases with increasing the rate of shear. Shear thinning fluids have a viscosity that decreases with increasing rate of shear. Thixotropic fluids become less viscous over time at a constant shear rate. Rheopectic fluids become more viscous over time at a constant sear rate. A Bingham plastic is a material that behaves as a solid at low stresses but flows as a viscous fluid at high stresses.

[0125] Most well fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. As used herein, a reference to viscosity is actually a reference to an apparent viscosity. Apparent viscosity is commonly expressed in units of centipoise ("cP").

[0126] Like other physical properties, the viscosity of a Newtonian fluid or the apparent viscosity of a non-Newtonian fluid may be highly dependent on the physical conditions, primarily temperature and pressure.

Viscosity Measurements

[0127] There are numerous ways of measuring and modeling viscous properties, and new developments continue to be made. The methods depend on the type of fluid for which viscosity is being measured. A typical method for quality assurance or quality control (QA/QC) purposes uses a Couette device, such as a Fann Model 35 or 50 viscometer or a Chandler 5550 HPHT viscometer, that measures viscosity as a function of time, temperature, and shear rate. The viscosity-measuring instrument can be calibrated, for example, by using standard viscosity silicone oils or other standard viscosity fluids.

[0128] Unless otherwise specified, the apparent viscosity of a fluid (excluding any suspended solid particulate larger than silt) is measured with a Fann Model 35 type viscometer using an Rl rotor, B l bob, and Fl torsion spring at a shear rate of 40 1/s, and at a temperature of 77 °F (25 °C) and a pressure of 1 atmosphere. For reference, the viscosity of pure water is about 1 cP.

[0129] A substance is considered to be a fluid if it has an apparent viscosity less than 5,000 cP (independent of any gel characteristic).

Cement Compositions

[0130] As used herein, "cement" refers to an inorganic cement (as opposed to organic cement and adhesives) that when mixed with water will begin to set and harden.

[0131] As used herein, a "cement composition" is a material including at least cement. A cement composition can also include additives. A cement composition can include water or be mixed with water.

What is claimed is:

1. A method comprising the steps of:

(A) obtaining or providing an apparatus comprising:

(i) a container forming a chamber;

(ii) a first surface exposed to or in the chamber, wherein the first surface is of a first electrode;

(iii) a second surface exposed to or in the chamber, wherein the second surface is of a second electrode;

wherein the first surface is electrically insulated from the second surface;

(B) wetting at least the first surface with a first liquid phase of a first bulk fluid;

(C) after the step of wetting, introducing a second bulk fluid into the chamber, wherein the second bulk fluid comprises a second liquid phase, and wherein the second liquid phase is immiscible with the first liquid phase;

(D) applying a shear between the second bulk fluid in the chamber and at least the first surface; and

(E) at least once during or after applying the shear, making an electrical impedance spectroscopy measurement between the first and second electrode.

2. The method according to claim 1, additionally comprising the steps of: before the step of applying the shear, making a first electrical impedance spectroscopy measurement between the first and second electrode; during or after the step of applying the shear, making a second electrical impedance spectroscopy measurement between the first and second electrode; comparing the first electrical impedance spectroscopy measurement to the second electrical impedance spectroscopy measurement; and based on the step of comparing, inferring any changes in the wetting of the first surface.

3. The method according to claim 1, wherein the first surface is curved.

4. The method according to claim 1, wherein the step of wetting comprises: (i) introducing the first bulk fluid into the chamber; and

(ii) applying a first shear between the first fluid in the chamber and at least the first surface.

5. The method according to claim 1, wherein the first liquid phase is oleaginous.

6. The method according to claim 1, wherein the second bulk fluid comprises any mixture of the first bulk fluid and the second liquid phase.

7. The method according to claim 1, wherein the second liquid phase comprises water.

8. The method according to claim 7, wherein the second liquid phase comprises an electrolyte.

9. The method according to claim 1, wherein the second bulk fluid comprises a surfactant.

10. The method according to claim 1, wherein the second bulk fluid comprises a solid particulate.

11. The method according to claim 1 , wherein the second bulk fluid is a foam.

12. The method according to claim 1, wherein the composition of the second bulk fluid is changed during the step of applying shear.

13. The method according to claim 1 , wherein the second bulk fluid is tested at the design shear and design time for a spacer fluid in a portion of a well.

14. The method according to claim 1, additionally comprising the step of: controlling the temperature of the second bulk fluid in the chamber, wherein the step of controlling the temperature of the second bulk fluid in the chamber comprises controlling the temperature to be the design temperature for a well fluid in a well.

15. The method according to claim 1, additionally comprising the step of: controlling the pressure of the second bulk fluid in the chamber, wherein the step of controlling the pressure of the second bulk fluid in the chamber comprises controlling the pressure to be the design pressure for a well fluid in a well.

16. The method according to claim 2, additionally comprising the steps of:

comparing the first electrical impedance spectroscopy measurement to the second electrical impedance spectroscopy measurement; and

based on the step of comparing, inferring any changes in the wetting of the first surface.

17. The method according to claim 16, wherein the step of inferring comprises assuming an equivalent electrical circuit model for the first electrical impedance spectroscopy measurement and second electrical impedance spectroscopy measurement to match experimental impedance changes using non-linear regression techniques.

18. The method according to claim 16, additionally comprising the step of: designing a composition of a first well fluid or conditions of introducing the first well fluid into a well to achieve a change in wetting of a downhole surface in the well.

19. The method according to claim 18, additionally comprising the step of: introducing the first well fluid into the well, wherein the well fluid and conditions of introducing are designed to achieve the desired change in wetting of a downhole surface in the well.

20. The method according to claim 19, additionally comprising the step of: after introducing the first well fluid into the well, introducing a second well fluid into the well to reach the downhole surface in the well.

21. The method according to claim 20, wherein the second well fluid is a cement composition.

22. A method comprising the steps of:

(A) positioning a first electrode and a second electrode in an annulus between a metallic tubular and the borehole of a wellbore in a well;

(B) pumping a fluid through though the annulus and between the first electrode and the second electrode; and

(C) at least once during or after the step of pumping, making an electrical impedance spectroscopy measurement between the first and second electrode.

23. An apparatus comprising:

(A) a container forming a chamber;

(B) a first surface exposed to or in the chamber, wherein the first surface is of a first electrode;

(C) a second surface exposed to or in the chamber, wherein the second surface is of a second electrode, and wherein the first surface is electrically insulated from the second surface;

(D) a first liquid phase wetted on at least the first surface;

(E) a bulk fluid in the chamber, wherein the bulk fluid comprises a second liquid phase, and wherein the second liquid phase is immiscible with the first liquid phase;

(F) a means for controlling the shear rate between the bulk fluid in the chamber and at least the first surface;

(G) an alternating electrical potential source operatively connected between the first and second electrodes;

(H) means for controlling the electrical potential or the frequency of the alternating electrical potential source; and

(I) means for measuring changes in electrical impedance between the first electrode and second electrode;

whereby electrical impedance spectroscopy measurements can be made between the first electrode and the second electrode before, during, or after controlling the shear rate.