Patent Application
20090188312
The drilling of well bores in subterranean formations commonly involves pumping a “drilling fluid” into a rotated drill string to which a drill bit is attached. The drilling fluid typically exits through openings in the drill bit, inter alia, to lubricate the bit and to carry cuttings up an annulus between the drill string and the well bore for disposal at the surface. One type of drilling fluid is an emulsion of substances that define a non-aqueous external phase and an aqueous internal phase. In this drilling fluid a non-aqueous “oleaginous” external phase (e.g., oil or synthetic polymers) may be used to inhibit swelling of water-sensitive drill cuttings (e.g., shale). Typical oil-based drilling fluids contain some amount of an internal aqueous phase. The emulsion often may be prepared by using an aqueous (water-based) internal phase comprising salts (e.g., calcium chloride). These oil- or synthetic-based drilling fluids also typically include chemical emulsifying agents that act to form oleaginous external phase emulsions, also known as “invert” emulsions. These chemical emulsifying agents also promote the oil-wetting of surfaces. This oil-wetted state promotes lubrication of the drill bit and further stabilization of formation materials.
After drilling is completed, a casing string commonly is cemented in the well bore as part of completing the well. One type of cementing operation includes placing a cement composition through the casing string and into the annulus to displace the drilling fluid from the annulus to the surface (however, flow in the opposite direction may occur in some operations, such as in reverse circulating or reverse cementing). A successful cementing operation also includes bonding the cement composition with the outer surface of the casing string and the inner surface of the well bore defining the annulus.
The bond formed between the cement composition and the outer surface of the casing string as well as the inner surface of the well bore may not be optimal if the casing string and well bore surfaces are not conducive to bonding with the cement composition. For example, the non-aqueous portion of the drilling fluid may coat the casing string and well bore surfaces. This may interfere with the bonding of the cement composition to the surfaces, because the aqueous cement composition generally will not bond readily with the non-aqueous substances that may coat the surfaces. If improper or incomplete bonding occurs at either of these surfaces, a thin region called a “micro-annulus” may be formed. Formation of a micro-annulus may lead to the loss of zonal isolation of the well bore, and undesirable fluid migration along the well bore casing string. Further, casing lifetime may be compromised if migrating fluids are corrosive.
Conventional attempts to solve this problem have involved displacement of the drilling fluid from the annular space between the formation and casing string, or between an inner casing and an outer casing strings so as to water-wet the formation and/or casing surfaces. Accordingly, it often may be desirable for the displacement fluid to invert the emulsion within the drilling fluid, while water-wetting the formation and/or casing surfaces.
A displacement fluid may be pumped ahead of the cement composition to create water-wet surfaces. Certain embodiments of such displacement fluids may cause a non-aqueous (hereafter “oleaginous”) external drilling fluid to invert, such that the aqueous internal phase becomes external, and the oleaginous phase becomes internal. Fluids that cause this inversion may be referred to as “inverter fluids,” and often may be suitable for use as displacement fluids. Examples of suitable inverter fluids include, inter alia, spacers and/or preflushes. Other nonlimiting examples of suitable inverter fluids include settable fluids and other compositions that comprise cementitious components such as hydraulic cements. Other nonlimiting examples of suitable inverter fluids are disclosed in, for example, U.S. Pat. Nos. 6,138,759, 6,524,384, 6,666,268, 6,668,929, and 6,716,282, the entire disclosures of which are incorporated herein by reference.
Conventional inverter fluids typically comprise an aqueous base fluid, viscosifying agents, and fluid loss control additives. Certain inverter fluids also may comprise, inter alia, weighting agents, surfactants, and salts. The weighting agents may be included in an inverter fluid, inter alia, to increase its density for well control, and to increase the buoyancy effect that the inverter fluid may impart to the drilling fluid and filter cake that may adhere to the walls of the well bore. Viscosifying agents may stabilize the suspension of particles within the inverter fluid, and may control fluid loss from the inverter fluid. The presence of a surfactant in the inverter fluid may enhance the chemical compatibility of the inverter fluid with other fluids (e.g., the drilling fluid, and/or a cement composition that subsequently may be placed against the formation) and may water-wet downhole surfaces, thereby improving bonding of the cement composition to surfaces in the formation, and may facilitate improved removal of well bore solids. A salt may be included in the inverter fluid, inter alia, for formation protection, improved compatibility among fluids in the formation, and to desirably affect wettability.
Inverter fluids also may be used to displace oleaginous-external/aqueous-internal fluids from cased hole or open hole well bores in operations other than cementing. One example involves replacement of these inverter fluids with a completion fluid (e.g., a solution of calcium chloride or bromide). This operation may be conducted to clean the well bore for further operations, such as perforation of the casing or, in the case of an open hole, the onset of production of the well. In this case, the inverter fluid may serve to displace the previous fluid and leave the formation surfaces in a water-wet state.
The use of inverter fluids in cementing and other subterranean operations often may be problematic, because of, inter alia, difficulties in identifying a specific inverter fluid composition that may desirably invert a particular drilling fluid composition in a manner so as to water-wet the annulus to a desired degree. Conventional attempts to identify specific inverter fluid compositions that may desirably invert a particular drilling fluid composition in a desired manner, at the temperature and pressure to which both fluids may be exposed in a subterranean environment, often have involved a multi-step process that may fail to identify incompatibilities between components of the fluids at the anticipated subterranean conditions. Commonly, a proposed inverter fluid composition has been pre-conditioned to the anticipated temperature and pressure using a high-pressure, high-temperature apparatus, then cooled, de-pressurized, and removed from the first apparatus, and placed in a testing apparatus at atmospheric pressure and only slightly elevated temperature, along with a sample of the drilling fluid that is to be inverted. This method is problematic because it may mask certain changes or conditions (e.g., cloud point changes, solubility changes, and the like) that may result in an incompatibility between the fluids and/or that may indicate that the proposed inverter fluid composition will not invert a particular drilling fluid composition in a desired manner at the desired temperature and pressure.
The accepted industry standard is to test compatibility of fluids at 180° to 190° F. and at atmospheric pressure, and assume that all greater pressures and temperatures will be covered. Currently, the American Petroleum Institute (API) recommends testing the rheologies of the following fluid ratios: 100% mud; 95% mud, 5% spacer; 75% mud, 25% spacer; 50% mud, 50% spacer; 25% mud, 75% spacer; 5% mud, 95% spacer; and 100% spacer. This normally requires that seven different fluids be prepared and then measured. This allows for cooling of the fluids during mixing, which may alter the outcome of the tests. Pending API Recommended Practice 10B-2 recommends starting at 100% mud and slowly mixing spacer at all ratios possible. However, this pending standard indicates atmospheric pressure and ambient temperature.
The present invention relates generally to subterranean operations involving multiple fluids within a subterranean environment. More particularly, the present invention relates to apparatus and methods for determining fluid compatibility in certain subterranean operations.
In one embodiment, a method of testing fluid compatibility may comprise placing a first fluid in a fixed-volume testing chamber, placing a second fluid in a sample chamber, heating the fixed-volume testing chamber to about a temperature of a subterranean environment, pressurizing the fixed-volume testing chamber to about a pressure of the subterranean environment; determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a first rheology value of the fluid within the fixed-volume testing chamber, moving a portion of the second fluid from sample chamber into the fixed-volume testing chamber, and determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a second rheology value of the fluid within the fixed-volume testing chamber.
In another embodiment, a method of testing fluid wettability may comprise placing a first fluid in a fixed-volume testing chamber, placing a second fluid in a sample chamber, heating the fixed-volume testing chamber to about a temperature of a subterranean environment, pressurizing the fixed-volume testing chamber to about a pressure of the subterranean environment, determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a first rheology value of the fluid within the fixed-volume testing chamber, determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a first wettability value of the fluid within the fixed-volume testing chamber, moving a portion of the second fluid from sample chamber into fixed-volume testing chamber, determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a second rheology value of the fluid within the fixed-volume testing chamber, and determining, at a temperature and pressure of about the temperature and pressure of the subterranean environment, a second wettability value of the fluid within the fixed-volume testing chamber.
In one embodiment an apparatus for testing fluid compatibility may comprise a fixed-volume testing chamber, a sample chamber in fluid communication with the fixed-volume testing chamber, a heating element for heating the fixed-volume testing chamber to about a temperature of a subterranean environment, a stepper motor for pressurizing the fixed-volume testing chamber to about a pressure of the subterranean environment, and a viscometer for determining rheology within the fixed-volume testing chamber.
The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments, which follows.
A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, wherein:
While the present invention is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown in the drawings and are herein described. It should be understood, however, that the description herein of specific embodiments does not limit the invention to the particular forms disclosed, but on the contrary, covers all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
The present invention relates generally to subterranean operations involving multiple fluids within a subterranean environment. More particularly, the present invention relates to apparatus and methods for determining fluid compatibility in certain subterranean operations.
In certain embodiments of the present invention, methods are provided for determining a suitable composition for a displacement fluid. In certain embodiments of the present invention, the displacement fluid may be an inverter fluid. Certain embodiments of the methods of the present invention comprise using an apparatus of the present invention to measure a value of a parameter related to the electrical conductivity and/or rheological compatibility of an initial mixture of (1) a test fluid having a composition nominally equivalent to the oleaginous external/aqueous internal fluid in the well and (2) part of a selected inverter fluid. In certain embodiments, this may be done while simulating downhole conditions for temperature and pressure. Certain embodiments of the methods of the present invention also comprise adding a further portion of the selected inverter fluid to the initial mixture, until the measured value of the parameter indicates the test fluid has inverted from an oleaginous-external/aqueous-internal state to an aqueous-external/oleaginous-internal state. An alternative embodiment tests the compatibility of various mixtures, such as those set by the American Petroleum Institute (API).
Referring now to
Within fixed-volume testing chamber 102, paddle 106 may be disposed in fluid 100. In certain embodiments of the present invention, paddle 106 may comprise a blender blade assembly. In certain embodiments of the present invention, such blender blade assembly may be a blade assembly typical of those used in high-temperature, high-pressure cement consistometers. Paddle 106 may be rotated by electric motor 108, which, in certain embodiments of the present invention, may comprise an AC or DC electric motor. In certain embodiments of the present invention, electric motor 108 may be a direct drive motor, wherein a drive shaft (not shown) penetrates fixed-volume testing chamber 102. In certain embodiments of the present invention, electric motor 108 may be a magnetic drive motor, wherein a drive shaft (not shown) does not penetrate fixed-volume testing chamber 102, but instead drives a drive sprocket or pulley 109 to rotate paddle 106. When a magnetic drive motor is used, it may be capable of variable speed operation, and rheological readings may be obtained at three or more speeds. In certain preferred embodiments of the present invention, the speed of electric motor 108 may be indicated in revolutions per minute (rpm) on an indicator (not shown). When fluid 100 within fixed-volume testing chamber 102 comprises a mixture of fluids (such as, for example, a test fluid, a portion of an inverter fluid to be tested, and any added substances), the stirring rate achieved using electric motor 108 and paddle 106 may be sufficient to quickly homogenize fluid 100, but not be so high that excessive shear may affect readings and surfactant performance. Stirring may cease for each fluid addition, and be restarted for rheological determinations.
Thermocouple 112 may be disposed within fixed-volume testing chamber 102, such that at least a portion of thermocouple 112 is immersed in fluid 100. Two electrodes 114, 116 are immersed in fluid 100 and connected to respective portions of the remaining electrical circuit shown in
The pressure within fixed-volume testing chamber 102 is indicated by pressure indicator 110, and may be controlled by a variety of means. Generally, the pressure within fixed-volume testing chamber 102 will increase as fixed-volume testing chamber 102 is heated to a desired temperature. Additional pressurization of fixed-volume testing chamber 102 may be achieved by injecting a fluid from fluid supply 128 into fixed-volume testing chamber 102 via pump 130. This may be done manually or automatically. When a fluid is injected into fixed-volume testing chamber 102 manually, the pressure on pressure indicator 110 may be visually observed, and pressure control valve 132 may be manually opened to permit fluid to be pumped into fixed-volume testing chamber 102 through pump 130. In the embodiment illustrated in
The temperature within fixed-volume testing chamber 102 may be controlled by a variety of means. In the embodiment illustrated in
In certain embodiments of the present invention, receiving tank 158 (shown in
Referring now to
Potentiometer 120, such as, for example, a Bourns 3S00s-2-102, sets the span of readings described below. In the circuit illustrated in
The apparatus shown in
Referring now to
As illustrated in
Optionally, as illustrated in
Generally, a calibrating procedure may be performed before the apparatus of the present invention is used. Before a test is run, the voltage or current relative to potentiometer 120 may be measured using meter 122/124 and only the oleaginous-external/water-internal drilling fluid used as fluid 100. This reading should be zero since fluid 100 should be nonconductive. A non-zero reading indicates the instrument is malfunctioning (e.g., an electrical short occurring through the instrument or electrodes 114, 116) or the oleaginous-external/aqueous-internal fluid is contaminated with water in the external phase. Alternatively, calibration may be done first with the proposed inverter fluid and then with the non-aqueous fluid. Next, after thoroughly cleaning testing chamber 102, the electrical parameter (voltage or current) may be measured with only the proposed inverter fluid (e.g., no drilling fluid is present) as fluid 100. This should give a non-zero reading through meter 122/124, which corresponds to a maximum voltage drop because the aqueous-based inverter fluid is electrically conductive. Potentiometer 120 may be adjusted until a desired maximum reading is obtained. Potentiometer 120 should not be adjusted after this setting is obtained. Once the zero value of potentiometer 120 and the maximum span value of potentiometer 120 have been determined using suitable calibrating fluids, the precise moment when the actual drilling fluid to be tested undergoes an external phase change, or inversion (thus wettability) may be determined.
Generally, the composition of the test oleaginous-external/aqueous-internal fluid may resemble the particular drilling fluid that may be used in the subterranean environment. In certain embodiments of the present invention, the test fluid may be only nominally equivalent to the actual fluid used (or that may be intended to be used) in the formation. As referred to herein, the term “nominally equivalent” will be understood to mean that the test fluid generally has the same composition as the oleaginous-external/aqueous-internal drilling fluid used during the drilling procedure, and that the test fluid generally also may be pre-conditioned to a comparable temperature and pressure to which the actual downhole fluid may be exposed. Though the term “nominally equivalent” includes, but is not limited to, exact identity between the fluids, the term also embraces slight differences in the test fluid and the drilling fluid (e.g., wherein the test fluid and the drilling fluid have different electrolyte contents). In certain embodiments of the present invention wherein the apparatus and methods of the present invention test are used at a well site, the test fluid may comprise a sample of a batch of the drilling fluid to be placed into the well bore.
The initial inverter fluid compositions to be tested against the test oleaginous-external/aqueous-internal fluid may be chosen by experience in dealing with the inverter fluids as known by one skilled in the art, with the benefit of this disclosure.
Generally, the drilling fluid to be used in the test will be preconditioned by increasing its pressure and temperature according to a desired schedule, until the drilling fluid reaches the temperature and pressure to which it is expected to be exposed in the subterranean environment. In certain embodiments of the present invention, this will be the particular well's bottom hole circulating temperature and pressure. In certain embodiments, the preconditioning schedule will approximate the variations in temperature and pressure to which the drilling fluid will be exposed during at least a portion of its passage through the subterranean environment. The drilling fluid may be preconditioned within the apparatus of the present invention, or within any other suitable apparatus. In certain embodiments of the present invention, the various selected fluids to be used in the test (e.g., the drilling fluid, the inverter fluid, and other fluids) may be placed in an apparatus of the present invention, and preconditioned therein by increasing their pressure and temperature according to a desired schedule, until the fluids reach the temperature and pressure to which the determined inverter fluid is expected to be exposed in the subterranean environment (e.g., the particular well's bottom hole circulating temperature and pressure). In certain embodiments, the preconditioning schedule will approximate the variations in temperature and pressure to which the fluids will be exposed during at least a portion of their passage through the subterranean environment. Such preconditioning generally ensures the fluids are stable and all chemicals have been conditioned.
After the calibration procedure described above has been performed on potentiometer 120, and the drilling fluid and/or other fluids to be tested have been preconditioned to a desired extent as described above, the actual testing of the combination of inverter fluid and oleaginous-external/water-internal drilling fluid may be performed, using one or both of two procedures, as well as other suitable procedures. The particular one(s) chosen may be based upon prior knowledge of the drilling fluid system, and the inverter fluids, including the behavior of the various surfactants. During this procedure, viscosity spikes that may occur at specific drilling fluid-to-inverter fluid and drilling fluid-to-surfactant ratios also may be observed and reported.
In one procedure, the drilling fluid to be tested and the selected inverter fluid may be mixed in a desired ratio (e.g., 50:50). The selected inverter fluid may or may not contain one or more surfactants when mixed with the drilling fluid. After the mixture is made homogenous by mixing with paddle 106, and while stirring of the mixture continues, one or more selected surfactants may be injected into this embodiment of fluid 100, and the electrical behavior may be observed through the response of meter 122/124. As the concentration of surfactants increases within this mixture, the reading from meter 122/124 will start to increase as the surfactants begin to invert the oleaginous-external drilling fluid and clean the surfaces of electrodes 114, 116. During this transition process, when the mixture of the inverter fluid and the drilling fluid is in a bicontinuous phase (often referred to as a Winsor Type III emulsion), the readings from meter 122/124 may fluctuate, dropping to a stable minimum value at equilibrium when the mixture homogenizes and the oil recoats the electrodes. Eventually, the reading from meter 122/124 will reach a maximum value equal to, or slightly greater than, that recorded for 100% inverter fluid (e.g., wherein drilling fluid is absent) as the fluid 100, thus indicating the electrodes are completely water-wetted and the mixture is 100% water-external (e.g., the drilling fluid has been inverted). The maximum reading may be slightly above that obtained with 100% spacer (e.g., due to salts dissolved in the aqueous phase of the drilling fluid). To ensure that inversion has actually occurred, the maximum reading should remain stable for a suitable length of time, such as twenty minutes. If the reading decreases, the appropriate surfactant(s) may again be added and the electrical response monitored until an electrically stable fluid has been obtained. Once the electrically stable fluid has been obtained, the concentration of the injected inverter fluid ingredient(s) (e.g., the one or more surfactants in this example) in the total mixture in fixed-volume testing chamber 102 may be determined. This total mixture includes the measured initial mixture (e.g., the initial mixture of drilling fluid and inverter fluid, in this example) plus the measured added portion of the injected inverter fluid ingredients (e.g., the one or more surfactants in this example). The concentration of the injected inverter fluid ingredients in only the total inverter fluid itself also may be readily determined. This concentration may be readily determined because the volume of inverter fluid in the initial mixture is known and the volume of added inverter fluid ingredients (e.g., surfactants) is known from the injection. The procedure described above is, of course, capable of numerous modifications, including, inter alia, embodiments wherein the testing is performed by mixing the drilling fluid to be tested along with a selected inverter fluid that already comprises a desired amount of surfactants.
In the second, alternative procedure, the inverter fluid initially may be prepared with one or more surfactants. Instead of injecting surfactant into an initial mixture of drilling fluid and inverter fluid, the drilling fluid may be present in fixed-volume testing chamber 102 without the inverter fluid, and then an inverter fluid may be injected into the drilling fluid, so as to determine the volume of inverter fluid required to invert the drilling fluid to a desired degree. The reading on meter 122/124 may be observed, and once the maximum reading is obtained for the suitable time period, the electrically stable fluid has been obtained, thereby identifying the ratio of the inverter fluid to the drilling fluid. That is, the total volume of the selected inverter fluid in the initial mixture (if any) and the added further portion of the selected inverter fluid are known or determined and the ratio of the final volume of the inverter fluid to the initial volume of the test oleaginous-external/aqueous-internal fluid in the initial mixture may be determined. The procedure described above is, of course, capable of numerous modifications.
Having used the apparatus of the present invention to determine parameters of the drilling fluid and inverter fluid, a number of determinations may be made. For example, depending on the viscosity profile of the drilling fluid, inverter fluid, and mixtures thereof, it may be desirable to adjust the surfactant such that the inversion from oleaginous-external to water-external occurs at some specified drilling fluid-to-inverter fluid ratio. For example, synthetic drilling fluids typically have a low yield point; therefore, when the phase change occurs, the now water-wetted solids of the drilling fluid may settle severely. This may lead to bridging in downhole casing tools and in the annulus when fluid velocities are insufficient to provide support. This also may lead to annular solids bed deposition on the low side of an inclined or horizontal well bore.
Conversely, some drilling fluid systems viscosify severely when inverted, especially in the presence of an aqueous spacer. Depending on where the viscosity peak occurs, it may be desirable to shift the drilling fluid-to-inverter fluid ratio such that inversion occurs away from the viscosity peak by adjusting the surfactant. The injection procedure wherein one or more surfactants are injected (rather than the entire inverter fluid) is best suited to pinpointing the critical surfactant concentration. Once that surfactant concentration is known, the inverter fluid injection procedure may be repeatedly used with alternate surfactant concentrations to find a drilling fluid-to-spacer ratio where inversion occurs but with a lower viscosity spike.
A properly designed inverter fluid should have adequate Theological properties to support solids released from the drilling fluid system. In the case of a drilling fluid system that loses solids-carrying capacity when it is inverted, it may be more desirable to adjust (typically reduce) the surfactant loading such that a higher percentage of inverter fluid is required to cause the external phase of the resulting mixture to become water-wet. This will result in more solids-carrying capacity, thus reducing the risk of dropping solids as described above.
In one embodiment of a method of the present invention, a method of designing an inverter fluid is provided that comprises designing an inverter fluid that intermixes with the oleaginous-external/aqueous-internal fluid to cause the oleaginous-external/aqueous-internal fluid (or at least a coating of this fluid on the outer surface of the tubular string or on the wall of the well bore) to invert. Designing the inverter fluid includes testing a selected inverter fluid with a test fluid having a composition nominally equivalent to the composition of the oleaginous-external/aqueous-internal fluid.
Once the desired inverter fluid has been designed, certain embodiments of the methods of the present invention further comprise making a quantity of the designed inverter fluid to be placed in the annulus of the well. This quantity may be placed in the well for inverting the oleaginous external/aqueous-internal fluid actually in the well on at least a portion of one or more surfaces of the annulus. One technique for placing the inverter fluid includes pumping the quantity of inverter fluid in the well along with a quantity of a cement composition such that the present invention also encompasses a method of cementing a well in addition to merely water wetting the well. In this application, the inverter fluid precedes the cement composition such that the pumped inverter fluid displaces at least part of the oleaginous-external/aqueous-internal fluid in the annular region and inverts the coating of oleaginous-external/aqueous-internal fluid sufficient to remove the coating ahead of the cement composition. At least part of the pumped inverter fluid may be subsequently displaced by the cement composition to obtain bulk cement displacement, but without an undesirable micro-annulus. Pumping of the fluids may be performed in a conventional or otherwise known manner (such as reverse-circulating or reverse cementing, for example).
Another technique for placing the inverter fluid includes pumping the quantity of inverter fluid in the well followed by a quantity of a completion fluid. Examples of completion fluids may include, for example, fresh water, along with aqueous salt solutions (e.g., brines). A broad variety of aqueous salt solutions may be suitable for use as completion fluids in certain embodiments, including, for example, solutions that comprise calcium chloride, sodium chloride, potassium chloride, calcium bromide, zinc bromide, and formate completion brines (e.g., cesium formate, potassium formate, and the like); other aqueous salt solutions also may be suitable. In this technique, displacing and inverting with the inverter fluid, and ultimately replacing the oleaginous-external fluid and the inverter fluid with the completion fluid prepares the well bore for future operations.
The testing and the making steps referred to above may be performed at the well or elsewhere (e.g., at a laboratory for the former and a manufacturing facility for the latter). The testing is in accordance with further aspects of the present invention described below. Making the designed inverter fluid may be performed in a conventional manner given a particular design obtained from the testing of the present invention. For example, in certain embodiments, the aqueous inverter fluid may be prepared at the well site. Mixing water may be measured into a field blender. Defoaming agents may be added, followed by a pre-blended dry material comprised of viscosifying agents and selected clays. Barite or other weighting agents may be added to adjust the specific gravity of the inverter fluid to a value usually slightly greater than that of the drilling fluid. Selected surface active agents (surfactants) may be added in sufficient quantity to perform the tasks of inverting the oil-based fluid and leaving well bore surfaces in a water-wet condition.
The process of testing in accordance with the present invention leads to a determination of a particular inverter fluid that may be used for inverting the particular test composition of oleaginous-external/aqueous-internal fluid against which the inverter fluid is tested. In the particular application of displacing and inverting a drilling fluid emulsion in an oil or gas well at the leading end of a stream of a cement composition being pumped into the well, the inverter fluid to be determined is typically in the class of fluids referred to as spacers. Such spacers typically are combined with one or more surfactants to make up the complete inverter fluid.
In block 406, the test fluid may be preconditioned. Those of ordinary skill in the art will appreciate that preconditioning of the test fluid may be performed prior to, simultaneously with, or subsequent to the steps depicted in blocks 402 and 404. Preconditioning of the test fluid may be performed as discussed above. For example, in some embodiments, preconditioning of the test fluid may comprise utilizing high temperature, high pressure equipment that is separate from the apparatus of the present invention. In other embodiments, preconditioning of the test fluid may occur in fixed-volume testing chamber 102 of an apparatus of the present invention depicted in
As depicted in block 408, a determination may be made as to whether preconditioning of the test fluid occurred in fixed-volume testing chamber 102. If preconditioning of the test fluid did occur in fixed-volume testing chamber 102, the execution of the method 400 moves to block 414. If preconditioning of test fluid did not occur in fixed-volume testing chamber 102, the test fluid may be added to fixed-volume testing chamber 102, as depicted in block 410. Once in fixed-volume testing chamber 102 the temperature and pressure of fixed-volume testing chamber 102 may be adjusted, as depicted in block 412, to the temperature and pressure that the oleaginous-external/aqueous-internal fluid that is being tested will encounter in the subterranean environment.
In block 414 of
Referring now to
In block 506, the test fluid may be preconditioned. Those of ordinary skill in the art will appreciate that preconditioning of the test fluid may be performed prior to, simultaneously with, or subsequent to the steps depicted in blocks 502 and 504. Preconditioning of the test fluid may be performed as discussed above. For example, in some embodiments, preconditioning of test fluid may comprise utilizing high temperature, high pressure equipment that is separate from the apparatus of the present invention. In other embodiments, preconditioning of the test fluid may occur in fixed-volume testing chamber 102 of an apparatus of the present invention depicted in
As depicted in block 508, a determination may be made whether preconditioning of the test fluid occurred in fixed-volume testing chamber 102. If preconditioning of the test fluid did occur in fixed-volume testing chamber 102, the execution of the method 500 moves to block 514. If preconditioning of test fluid did not occur in fixed-volume testing chamber 102, the test fluid may be added to fixed-volume testing chamber 102, as depicted in block 510. Once in fixed-volume testing chamber 102 the temperature and pressure of fixed-volume testing chamber 102 may be adjusted, as depicted in block 512, to the temperature and pressure that the oleaginous-external/aqueous-internal fluid that is being tested will encounter in the subterranean environment.
In block 514 of
In another exemplary embodiment, as shown in
Temperature and pressure measurements may be taken in either or both chambers (102 and 194). Fixed-volume testing chamber 102 and sample chamber 194 may be heated via heating element to about the temperature of the subterranean environment where the fluids will be used. Fixed-volume testing chamber 102 may be pressurized to about the pressure of the subterranean environment. Sample chamber 194 may be similarly pressurized. For example, first fluid may be heated and pressurized according to the appropriate API test schedule for the depth and temperature gradient the fluids will experience. For example, temperatures above 190°. In some embodiments, the temperature may be up to 500° or even 600° or more. Preferably, but not necessarily, the two chambers may be heated and/or pressurized at the same time.
Paddle 106 may be stirred at 150 RPM during this conditioning period. Once final temperature and pressure, corresponding to a temperature and pressure of about the temperature and pressure of the subterranean environment are achieved, the first fluid may be stirred for an additional 20 minutes to fully condition. A first wettability and/or rheology measurement may be taken in fixed-volume testing chamber 102. A minimum of three wettability and/or rheology readings may then be recorded at varying speeds ranging from 2 to 150 RPM. Generally, the first measured value corresponds with 100% of the first fluid. Stirring may be reinitiated at 150 RPM. The wettability measurement may be obtained from contacts inside fixed-volume testing chamber 102 via the two probes at cross-section A-A, as is schematically illustrated in
Stirring may be stopped and 5% by volume of second fluid to be tested for compatibility may then be injected, forced, or otherwise moved from sample chamber 194 through stepper motor 202 and actuator 204 into fixed-volume testing chamber 102. This may displace a portion of the first fluid, causing it to escape from an opposite side of fixed-volume testing chamber 102. Thus, fluid 100 within fixed-volume testing chamber 102 may become a mixture of first fluid and second fluid. If second fluid is preheated to circulating temperature prior to injection, a minimum of three wettability and/or rheology reading may be recorded for fluid 100 within fixed-volume testing chamber 102 immediately at the same varying speeds used for the first fluid. If the second fluid was not preheated, fluid 100 within fixed-volume testing chamber 102 may be stirred for 20-30 minutes prior to taking wettability and/or rheology readings to allow the temperature to stabilize. The time will depend on how long it takes fluid 100 within fixed-volume testing chamber 102 to achieve the designated test temperature and pressure, corresponding to the temperature and pressure of about the temperature and pressure of the subterranean environment. Once the designated temperature and pressure are achieved, a second wettability and/or rheology measurement may be taken in fixed-volume testing chamber 102.
Stirring may be stopped and enough second fluid injected into fixed-volume testing chamber 102 to yield a final mixture ratio of 25% second fluid/75% first fluid. The same procedures may be used regarding temperature conditioning, etc. Once fluid 100 within fixed-volume testing chamber 102 are conditioned, the same wettability and/or rheology readings may be taken.
Stirring may again be stopped and enough second fluid injected into fixed-volume testing chamber 102 to yield a final mixture ratio of 50% second fluid/50% first fluid. Again, the same procedures as before may be applied.
Stirring may again be stopped and enough second fluid injected into fixed-volume testing chamber 102 to yield a final mixture ratio of 75% second fluid/25% first fluid. The same procedures may be followed as in previous steps.
Stirring may again be stopped and enough second fluid injected into fixed-volume testing chamber 102 to yield a final mixture ratio of 95% second fluid/5% first fluid. The same procedures may be followed as in previous steps.
Stirring may be stopped once more and enough second fluid injected to ensure that fixed-volume testing chamber 102 is completely full of second fluid. This may require a full chamber volume of displacement. Final wettability and/or rheology readings may be obtained at the same shear rates as before.
If it may not be determined that only second fluid remains in fixed-volume testing chamber 102, it may be desirable to cool fixed-volume testing chamber 102 and sample chamber 194 and completely clean them before calibrating and testing is repeated with the fluids introduced in the opposite order to check some of the previous measurements. In particular, the measurements for the 50:50 ratio should be the same whether fixed-volume testing chamber 102 initially contains the first fluid or fixed-volume testing chamber 102 initially contains the second fluid. In addition to using the methods described for contamination of spacer with mud when the spacer is used behind a cement slurry. This procedure can also be used to determine compatibility between the spacer and the cement.
While specific exemplary measurements are disclosed, any number of other measurements may be taken. For example, a viscometer may be used to take rheology measurements on any mixture of first fluid and second fluid. The retrofitted consistometer described in
Additionally, other types of measurements, including wettability, may be taken. For example, a potentiometer may be used to take wettability measurements on any mixture of first fluid and second fluid. Continual or near-continual measurements may also be taken. In this instance, the first rheology value may be measured when fluid 100 within fixed-volume testing chamber 102 have a percentage of the first fluid and a percentage of the second fluid. The second rheology value may be measured when fluid 100 within fixed-volume testing chamber has a smaller percentage of first fluid and a larger percentage of second fluid. Therefore, any number of measurements may be taken as the second fluid is introduced into fixed-volume testing chamber 102. Also, the fluid that is transferred to effluent chamber 196 can be cooled and removed from effluent chamber 196 through valves 206 and 208, for additional tests such as rheology, stability, and visual observation for wettability.
This method may be used to take API contamination level measurements, such that the first Theological measurement are taken on 100% drilling fluid, 95% drilling fluid and 5% spacer fluid, 75% drilling fluid and 25% spacer fluid, 50% drilling fluid and 50% spacer fluid, 25% drilling fluid and 75% spacer fluid, 5% drilling fluid and 95% spacer fluid, and 100% spacer fluid.
Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted and described by reference to embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alternation, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.
The present application claims priority under 35 U.S.C. § 119(e) from U.S. Provisional Patent Application No. 60/603,947, entitled “Apparatus And Methods For Improved Fluid Displacement In Subterranean Formations,” and filed on Aug. 24, 2004, the disclosure of which is incorporated herein by reference in its entirety. This application is a continuation in part of commonly-owned U.S. patent application Ser. No. 11/524,060, filed Sep. 20, 2006, entitled Apparatus and Methods for Improved Fluid Displacement in Subterranean Formations” by James F. Heathman, et al., which is a divisional patent application of commonly-owned U.S. Pat. No. 7,128,149, filed Aug. 24, 2005, entitled “Apparatus and Methods for Improved Fluid Displacement in Subterranean Formations,” by James F. Heathman, et al., which are both incorporated by reference herein for all purposes. This application is also related to U.S. Pat. No. 7,128,142, filed Aug. 24, 2005, entitled “Apparatus and Methods for Improved Fluid Displacement in Subterranean Formations,” the entirety of which is herein incorporated by reference.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 11211974 | Aug 2005 | US |
| Child | 11524060 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 11524060 | Sep 2006 | US |
| Child | 12355018 | US |
