阅读说明：本技术 使用钻井液的比热容确定钻井液的其他性质 (Determining other properties of drilling fluids using specific heat capacity of drilling fluids ) 是由 K·G·克莱恩古特尔 B·A·杰克逊 于 2017-04-12 设计创作，主要内容包括：提供了一种监测和控制钻井中使用的钻井液的一种或多种性质的方法。所述方法包括使所述钻井液循环穿过井筒,测量所述钻井液的比热容,以及至少部分地基于所述钻井液的所述测量的比热容来确定所述钻井液的另外性质的值。例如,所述钻井液的所述另外性质可以是所述钻井液的油水比。作为另一个示例,所述钻井液的所述另外性质可以是所述钻井液中的固体的平均比重。(A method of monitoring and controlling one or more properties of a drilling fluid used in drilling is provided. The method includes circulating the drilling fluid through a wellbore, measuring a specific heat capacity of the drilling fluid, and determining a value of an additional property of the drilling fluid based at least in part on the measured specific heat capacity of the drilling fluid. For example, the additional property of the drilling fluid may be the oil-water ratio of the drilling fluid. As another example, the additional property of the drilling fluid may be an average specific gravity of solids in the drilling fluid.)

1. A method of monitoring and controlling one or more properties of a drilling fluid used in drilling a well, the method comprising:

circulating the drilling fluid through the wellbore;

measuring a specific heat capacity of the drilling fluid after circulating the drilling fluid through the wellbore; and

determining a value of an additional property of the drilling fluid based at least in part on the measured specific heat capacity of the drilling fluid.

2. The method of claim 1, wherein the drilling fluid is circulated through the wellbore and a fluid treatment unit.

3. The method of claim 2, wherein the fluid treatment unit is located on the surface adjacent to the wellbore.

4. The method of claim 3, wherein the drilling fluid is circulated through the wellbore, the fluid handling unit, and a mud retention basin also located on the surface adjacent the wellbore, and wherein the fluid handling unit is located upstream of the mud retention basin.

5. The method of claim 3, wherein the drilling fluid is circulated through the wellbore, the fluid handling unit, and a mud retention basin also located on the surface adjacent the wellbore, and wherein the fluid handling unit is located in the mud retention basin.

6. The method of claim 3, wherein the drilling fluid is circulated through the wellbore, the fluid handling unit, a mud retention basin also located on the surface adjacent the wellbore, and a mixer also located on the surface adjacent the wellbore and downstream of the mud retention basin, and wherein the fluid handling unit is located downstream of the mixer.

7. The method of claim 1, wherein the specific heat capacity of the drilling fluid is measured at two or more fluid pressures, and wherein the additional property of the drilling fluid is determined based at least in part on the specific heat capacity measured at each fluid pressure.

8. The method of claim 1, wherein the specific heat capacity of the drilling fluid is measured at a temperature above or below ambient temperature.

9. The method of claim 1, further comprising providing a representation comprising a plurality of possible values of the additional property of the drilling fluid, each possible value corresponding to a predetermined specific heat capacity of the drilling fluid, and wherein the additional property of the drilling fluid is determined by: comparing the measured specific heat capacity of the drilling fluid to the predetermined specific heat capacity of the representation, and selecting the possible values of the additional property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid.

10. The method of claim 1, wherein the determined value of the additional property of the drilling fluid is an oil-water ratio of the drilling fluid.

11. The method of claim 1, wherein the determined value of the additional property of the drilling fluid is an average specific gravity of the solids in the drilling fluid.

12. The method of claim 1, wherein a value of a first additional property of the drilling fluid and a value of a second additional property of the drilling fluid are determined based at least in part on the measured specific heat capacity of the drilling fluid.

13. The method of claim 12, further comprising providing a separate representation for each of the first and second additional properties, each representation comprising a plurality of possible values of a respective additional property of the drilling fluid, each possible value corresponding to a predetermined specific heat capacity of the additional property of the drilling fluid, and wherein each of the first and second additional properties of the drilling fluid is determined by: comparing the measured specific heat capacity of the drilling fluid with a predetermined specific heat capacity of a respective representation, and selecting the possible values of the further property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid.

14. The method of claim 13, wherein the first additional property of the drilling fluid is the oil-water ratio of the drilling fluid and the second additional property of the drilling fluid is the average specific gravity of the solids in the drilling fluid.

15. The method of claim 1, further comprising adjusting at least one property of the drilling fluid in response to the determined additional property of the drilling fluid.

16. The method of claim 15, further comprising adjusting one or more of the oil-water ratio of the drilling fluid, the composition of the drilling fluid, the solids content of the drilling fluid, and the average specific gravity of the solids in the drilling fluid in response to the determined additional property of the drilling fluid.

17. The method of claim 14, further comprising adjusting at least one property of the drilling fluid in response to the determined oil-water ratio of the drilling fluid and the determined average specific gravity of the solids in the drilling fluid.

18. The method of claim 2, wherein the fluid treatment unit comprises:

a specific heat capacity sensor; and

a computer associated with the specific heat capacity sensor.

19. A method of monitoring and controlling the oil-water ratio of a drilling fluid used in drilling a well, the method comprising:

circulating the drilling fluid through the wellbore;

measuring a specific heat capacity of the drilling fluid after circulating the drilling fluid through the wellbore;

providing a representation comprising a plurality of possible values of the oil-water ratio of the drilling fluid, each possible value corresponding to a predetermined specific heat capacity of the drilling fluid;

determining the oil-water ratio of the drilling fluid based at least in part on the measured specific heat capacity of the drilling fluid by: comparing the measured specific heat capacity of the drilling fluid to the predetermined specific heat capacity of the representation, and selecting the oil-water ratio corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid; and

adjusting at least one property of the drilling fluid in response to the determined additional property of the drilling fluid.

20. A method of monitoring and controlling the average specific gravity of solids in a drilling fluid used in drilling a well, the method comprising:

circulating the drilling fluid through the wellbore;

measuring a specific heat capacity of the drilling fluid after circulating the drilling fluid through the wellbore;

providing a representation comprising the plurality of possible values of the drilling fluid, each possible value corresponding to a predetermined specific heat capacity of the drilling fluid;

determining the average specific gravity of the solids in the drilling fluid based at least in part on the measured specific heat capacity of the drilling fluid by: comparing the measured specific heat capacity of the drilling fluid to the predetermined specific heat capacity of the representation, and selecting the oil-water ratio corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid; and

adjusting at least one property of the drilling fluid in response to the determined additional property of the drilling fluid.

21. The method of claim 20, wherein the drilling fluid is circulated through the wellbore using a pumping apparatus.

Background

While drilling, drilling fluids are continuously circulated from the surface through the wellbore and back to the surface to perform various functions. For example, drilling fluids, also known as drilling muds, are used to remove cuttings from the wellbore, control formation pressure, and cool, lubricate, and support the drill bit. Typically, the drilling fluid is pumped down the wellbore through the interior of the drill string, pumped out via nozzles in the drill bit end, and then returned to the surface via the annular space between the drill string and the wellbore wall. At the surface, the drilling fluid is circulated through a series of shakers and other types of equipment to recover the drilling fluid and make it suitable for continued circulation through the wellbore.

Due to reaction with the drill cuttings, fluid loss into the formation, and other factors, the properties of the drilling fluid may change as the drilling fluid circulates through the wellbore. Therefore, the composition and other properties of the drilling fluid must be carefully monitored and controlled while drilling.

Many drilling parameters, such as measured depth, drill string rotation speed, weight on the bit, downhole torque, surface pressure, downhole pressure, bit orientation, and bit deflection, may be measured and adjusted in real time (i.e., continuously) or at least frequently as the drilling process progresses. However, some properties of the drilling fluid, such as the oil-to-water ratio in the drilling fluid and the average specific gravity of the solids in the drilling fluid, cannot be easily measured and adjusted in real time, or even frequently.

For example, in order to determine the oil-to-water ratio of a drilling fluid and the average specific gravity of solids in the drilling fluid, a drilling fluid engineer or mud engineer (hereinafter "mud engineer") must directly measure such properties. Typical field mud engineers have many other duties in their daily routine and typically measure the oil-to-water ratio of the drilling fluid and/or the average specific gravity of the solids in the drilling fluid only every few hours. Even if the mud engineer is able to measure these properties more frequently, the current methods of making the measurements are complex and time consuming. For example, mud engineers may need to spend up to an hour or more to directly measure the oil-to-water ratio of the drilling fluid and the average specific gravity of the solids in the drilling fluid. Depending on the nature of the formations penetrated by the drill bit, the expected types of hydrocarbons (e.g., oil and gas) associated with the formations, and other factors, such time ranges may not be sufficient in all circumstances.

Drawings

The drawings included in this application illustrate certain aspects of the embodiments described herein. However, the drawings should not be considered as exclusive embodiments. The subject matter disclosed herein is capable of considerable modification, alteration, combination, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent art.

FIG. 1 is a graph showing an example of a representation depicting a correlation between the specific heat capacity of a drilling fluid and the oil-water ratio of the drilling fluid.

FIG. 2 is a graph illustrating an exemplary representation depicting a correlation between the specific heat capacity of a drilling fluid and the average specific gravity of solids in the drilling fluid.

Fig. 3 is a diagram illustrating an example of a wellbore drilling system that may be used in accordance with certain embodiments of the present disclosure.

Fig. 4 is a diagram illustrating an example of a wellbore drilling system according to the present disclosure, with a fluid handling unit located in a mud-holding pit.

Fig. 5 is a diagram illustrating an example of a wellbore drilling system according to the present disclosure, with a fluid handling unit downstream of a blending hopper.

Fig. 6 is an enlarged view of a portion of a fluid processing cell particularly relevant to the methods disclosed herein.

Detailed Description

The present application may be understood more readily by reference to this detailed description and the examples included herein. For simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the disclosed subject matter. However, it will be understood by those of ordinary skill in the art that the subject matter described herein may be practiced without these specific details. In other instances, methods, procedures, and components have not been described in detail so as not to obscure the relevant features described. Moreover, this description is not to be taken as limiting the scope of the subject matter described herein. The figures are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate the details and features of the present application.

In accordance with the present disclosure, a method of monitoring and controlling one or more properties of a drilling fluid used in drilling is provided. For example, in one embodiment, the method is a method of monitoring and controlling the oil-water ratio of a drilling fluid used in drilling. In another embodiment, the method is a method of monitoring and controlling the average specific gravity of solids in a drilling fluid used in drilling. As used herein and in the appended claims, the term "drilling fluid" and the term "drilling mud" are used interchangeably and mean the same thing.

As used herein and in the appended claims, drilling refers to drilling a wellbore from the surface to a point below the surface. Wellbores may penetrate one or more subterranean formations containing, for example, water and/or hydrocarbons, such as oil and gas. The drilling fluid may be any type of drilling fluid that may be used for drilling a well. For example, the drilling fluid may be an emulsion having an aqueous continuous phase and an oil discontinuous phase, or an inverse emulsion having an oil continuous phase and an aqueous discontinuous phase.

The disclosed method comprises:

circulating the drilling fluid through a wellbore;

measuring a specific heat capacity of the drilling fluid after circulating the drilling fluid through the wellbore; and determining a value of an additional property of the drilling fluid based at least in part on the measured specific heat capacity of the drilling fluid.

The drilling fluid is circulated from the surface through the wellbore and back to the surface. Typically, the drilling fluid is pumped down the wellbore through the interior of the drill string, pumped out via nozzles in the drill bit end, and then returned to the surface via the annular space between the drill string and the wellbore wall (i.e., the inner surface of the wellbore). For example, in drilling oil and gas wells, the drilling fluid is also typically circulated through various types of equipment to recover and make the drilling fluid suitable for continued circulation through the wellbore.

For example, as shown in fig. 3, 4, and 5, which are described further below, the drilling fluid may be circulated through the wellbore and the fluid treatment unit. A fluid treatment unit may be located on a surface adjacent to the wellbore. For example, drilling fluid may be circulated through a wellbore, a fluid treatment unit, and a mud retention reservoir, also located on the surface adjacent to the wellbore. The fluid treatment unit may be located upstream of the holding tank, or in the mud holding tank. As another example, drilling fluid may be circulated through a wellbore, a fluid treatment unit, a mud holding pit, and a mixer also located on a surface adjacent to the wellbore. The mixer may be located downstream of the mud-holding tank, and the fluid-handling unit may be located downstream of the mixer.

As used herein and in the appended claims, measuring the specific heat capacity of a drilling fluid "after" circulating the drilling fluid through a wellbore refers to measuring the specific heat capacity of a portion of the drilling fluid after the portion has been circulated at least to some extent through the wellbore. For example, after a portion of the drilling fluid has been circulated from the surface through the wellbore and back to the surface, the specific heat capacity of the portion of the drilling fluid may be measured at the surface. For example, the specific heat capacity of the circulating portion of the drilling fluid may be measured as the remaining drilling fluid continues to circulate through the wellbore.

The specific heat capacity of the circulating drilling fluid can be measured quickly and accurately. For example, the fluid processing unit may include a specific heat capacity sensor, such as a specific heat capacity probe; and a computer associated with the specific heat capacity sensor. As used herein and in the appended claims, "computer" means a computer or other apparatus that includes a central processing unit and has one or more computer programs associated with the central processing unit.

For example, as the drilling fluid circulates through the fluid processing unit, the specific heat capacity of the drilling fluid may be measured by a specific heat capacity probe or other sensor, and a signal including a value of the specific heat capacity of the drilling fluid may be sent to a computer for further processing. For example, specific heat capacities may be measured at two or more fluid pressures, and additional properties of the drilling fluid may be determined based at least in part on the specific heat capacities measured at each fluid pressure. For example, the specific heat capacity of the drilling fluid may be measured at a temperature above or below ambient temperature. For example, the specific heat capacity of the drilling fluid may be measured at a temperature above ambient temperature. For example, the specific heat capacity of the drilling fluid may be measured at a temperature below ambient temperature.

For example, the specific heat capacity of the water and oil phases of a drilling fluid depends on pressure and temperature. At increased fluid pressures, the fluid portion of the drilling fluid contents tend to compress, which results in a change in the specific heat capacity of the water and oil phases of the drilling fluid. At increased pressure, the concentration of the fluid portion of the drilling fluid will also diminish compared to the complete drilling fluid.

It has been shown that the oil in the drilling fluid will generally compress more than the water in the drilling fluid and the density of the solids in the drilling fluid will generally remain constant. This changes the fractional concentration of individual components (e.g., oil, water, and solids) relative to the total fluid. As the concentration of the individual components changes, the specific heat capacity of the fluid will change, which allows the concentration of each component to be back-calculated from the change in concentration of the respective component. As the temperature of the fluid changes, the individual components (e.g., oil, water, and solids) will also have a change in specific heat capacity. However, the change in specific heat capacity due to a change in temperature is different for each component. If the specific heat capacity is measured at a sufficient temperature, the fractional concentrations of the individual components can be back-calculated.

Specific heat capacity is a measure of the amount of heat required to raise the temperature of a substance by one degree. The total specific heat capacity of the drilling fluid depends on the specific heat capacity of the components that produce the drilling fluid. As used herein and in the appended claims, the term "specific heat" and the term "specific heat capacity" are used interchangeably and mean the same thing.

For example, the following table shows the specific heat capacity of the most common elements in invert emulsion drilling fluids.

As shown, the liquid has a higher specific heat than the solid. Liquids also constitute a majority of fluids compared to solids.

A common method of determining the specific heat capacity of a drilling fluid utilizes a weighted average of the specific heat capacities of the individual components of the drilling fluid. Specifically, the weighted average of each individual component is summed together to obtain the total specific heat capacity of the drilling fluid. This can be seen in equation (1) below, where h_{General assembly}Is the specific heat capacity of the drilling fluid, h_nIs the specific heat capacity of the individual components, andis the fraction of the components in the total (by mass or volume).

An additional equation that may be used to determine the specific heat capacity of a drilling fluid is to use known or measured concentrations of the individual components of the drilling fluid and the corresponding specific heat capacities. This can be seen in equation (2), whereIs the concentration of oil, h_oIs the specific heat capacity of the oil and,is the concentration of water or brine, h_BIs the specific heat capacity of water or brine, h_LGSIs the specific heat capacity of a low gravity solid ("LGS"),is the LGS concentration, h_HGSIs the specific heat capacity of a high gravity solid ("HGS") or weighting agent, andis the concentration of HGS or weighting agent.

For example, the concentrations of the individual components of the drilling fluid may be determined by a variety of measurement methods or in other ways for determining the concentrations. For example, the individual concentrations may be determined by means of mud balancing and distillation, which is usually done by mud engineers. For example, the specific heat capacity of the individual components can be determined by: the specific heat capacity of the individual components is measured individually, and the values of the specific heat capacities of the individual components are stored in a database or similar data storage element that can be called at any time. The specific heat capacity of the individual components and known or measured concentrations of the individual components may then be used to determine the total specific heat capacity of the drilling fluid. If the mud engineer does not have a specific heat sensor or probe on hand, this can be done easily in the field to predict the specific heat of the mud or other drilling fluid, which in turn can help predict how the drilling fluid is operating downhole.

Alternatively, the total specific heat capacity of the drilling fluid may be measured using specific heat capacity sensors, including but not limited to commercially available specific heat capacity probes. The specific heat capacity sensor may be any type of specific heat capacity sensor that may be used to measure the specific heat capacity of a fluid. Such sensors measure the specific heat of the complete drilling fluid, rather than the specific heat of the individual components.

The value of the additional property of the drilling fluid can also be determined quickly and accurately according to the disclosed method by determining the value indirectly, for example based on a measured specific heat capacity of the drilling fluid. For example, the disclosed method may also include providing a representation of a plurality of possible values including additional properties of the drilling fluid, each possible value corresponding to a predetermined specific heat capacity. Additional properties of the drilling fluid may then be determined by: the measured specific heat capacity of the drilling fluid is compared to a predetermined specific heat capacity that is representative, and a possible value of the additional property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid is selected.

For example, the method may be used to determine the extent to which a drilling fluid is contaminated. For example, the initial drilling fluid specific heat may be measured before any contamination occurs. As drilling begins, contamination of the drilling fluid by low gravity solids may occur. At this point, the specific heat of the drilling fluid may again be measured. The contamination that has occurred can be quantified by using the following equation (3)Therein is formed ofIs the concentration of the contaminant, h_ContaminantsIs the specific heat of the contaminant, h_{Slurry composition}Specific heat of drilling fluid, h, measured after contamination_InitialIs the initial specific heat of the drilling fluid.

As used herein and in the appended claims, the term "representing" refers to a graph, table, electronic database, or other print or electronic data compilation that includes a plurality of possible values of additional properties of the drilling fluid (each possible value corresponding to a predetermined specific heat capacity), and: (a) allowing the measured specific heat capacity of the drilling fluid to be compared to a predetermined specific heat capacity in the representation; and (b) allow selection of a possible value of the additional property corresponding to a predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid. For example, the representation may be an electronic database comprising a plurality of possible values of the additional property of the drilling fluid (each possible value corresponding to a predetermined specific heat capacity) and capable of being manipulated by a computer program and a computer to compare the measured specific heat capacity of the drilling fluid to the predetermined specific heat capacities in the database and to select the possible value of the additional property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid.

For example, in one embodiment, the value of an additional property of the drilling fluid determined according to the disclosed method is the oil-to-water ratio of the drilling fluid. The oil-water ratio of a drilling fluid is the ratio of the volume percent of oil to the volume percent of water in the drilling fluid. In another embodiment, the value of the additional property of the drilling fluid determined according to the disclosed method is the average specific gravity of the solids in the drilling fluid. The average specific gravity of a drilling fluid is the average of the ratio of the density of each solid in the drilling fluid (e.g., weighting agent and drilling solids) to the density of water.

For example, if the representation is a graph or table, the measured specific heat capacity of the drilling fluid may be compared to a predetermined specific heat capacity of the representation, and a possible value of the additional property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid may be manually selected by an operator. For example, FIG. 1 shows a graph plotting possible values of oil-to-water ratio of a drilling fluid (at three different solids concentrations) versus a predetermined specific heat capacity of the drilling fluid. In using the graph of FIG. 1, the operator can only find a predetermined specific heat capacity on the y-axis of the graph that matches the measured specific heat capacity and then find the corresponding oil-to-water ratio on the x-axis of the graph. Figure 2 shows a similar graph plotting possible values of the average specific gravity of the solids in the drilling fluid (at two different solids concentrations) against a predetermined specific heat capacity of the drilling fluid. The graph of fig. 2 may be used in the same manner as the graph of fig. 1.

On the other hand, if the representation is an electronic database associated with a computer, the measured specific heat capacity of the drilling fluid may be compared to a predetermined specific heat capacity of the representation, and a possible value of the additional property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid may be automatically selected by the computer.

If desired, values for various properties of the drilling fluid may be determined based at least in part on the measured specific heat capacity of the drilling fluid. For example, the value of the first additional property of the drilling fluid and the value of the second additional property of the drilling fluid may be determined based at least in part on a measured specific heat capacity of the drilling fluid. For example, the method may further comprise providing a separate representation for each of the first and second further properties, each representation comprising a plurality of possible values of the respective further property of the drilling fluid, and each possible value corresponding to a predetermined specific heat capacity of the further property of the drilling fluid. Each of the first and second further properties of the drilling fluid may then be determined by: the measured specific heat capacity of the drilling fluid is compared to a predetermined specific heat capacity of the respective representation, and possible values of the further property corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid are selected. For example, the first additional property of the drilling fluid may be the oil-to-water ratio of the drilling fluid, and the second additional property of the drilling fluid may be the average specific gravity of the solids in the drilling fluid.

Specific heat measurements can be combined with other measurements (such as density at different pressures or even specific heat) if desired, and the concentrations of the individual components can be determined. For example, the method can be used to achieve more accurate and precise measurements than can be achieved by reference to tables and curves or by focusing on a contaminating component.

For example, in oil-based muds, there are four major components (high gravity solids (HGS), Low Gravity Solids (LGS), oil, and water). In water-based muds, there are three main components (HGS, LGS, and water), which means that there are three or four unknowns (concentrations of the components). A system of equations may be created and solved to find the concentration of each individual component. For example, the following equations (4), (5) and (6) may be used in conjunction with water-based muds, where the specific heat measurement is supplemented by the density measurement:

and is

Wherein h is_{Slurry composition}Is the specific heat capacity of the drilling fluid,is the concentration of water or brine, h_BIs the specific heat capacity of water or brine,is the concentration of the low gravity solid, h_LGSIs the specific heat capacity of a low gravity solid,is the concentration of a high gravity solid, h_HGSIs the specific heat capacity, rho, of a high gravity solid_{Slurry composition}Is the density of the drilling fluid, p_BIs the density of water or brine, and p_LGSIs the density of a low gravity solid. The density measurement may be replaced by any other measurement and even a specific heat measurement at a different temperature or pressure may be used as this will change the relative specific heat and volume fraction previously discussed.

The disclosed method may further include adjusting at least one property of the drilling fluid in response to the determined additional property of the drilling fluid. For example, the properties of the drilling fluid and/or the composition of the drilling fluid may be varied as desired based on the oil-to-water ratio and/or the average specific gravity of the solids to improve the performance of the drilling fluid and the efficiency of the drilling operation. Continuous monitoring of the oil-to-water ratio and/or the average specific gravity of the solids in the drilling fluid helps to maintain optimal fluid properties. The oil-to-water ratio of the drilling fluid and/or the average specific gravity of the solids in the drilling fluid are required inputs for many mud prediction models and software applications and help mud engineers provide the best fluid solutions.

For example, based on a determined oil-to-water ratio for the drilling fluid, it may be determined that more water needs to be added to the drilling fluid in order to improve the rheology of the fluid and reduce the overall cost of the fluid. Based on the determined average specific gravity of the solids in the drilling fluid, it may be determined that a reduction in the amount of low gravity solids in the drilling fluid is desirable to increase the rate of penetration, place less stress on the drill bit, and eliminate other problems that slow down or otherwise impede the drilling process. For example, if the average specific gravity of the solids is too low, the mud engineer may require adjustments to the solids control equipment, or the mud may be diluted to adjust the properties of the fluid to bring the properties back within the desired specification range.

For example, one or more of the oil-water ratio of the drilling fluid, the composition of the drilling fluid, the solids content of the drilling fluid, and the average specific gravity of the solids in the drilling fluid may be adjusted based on the oil-water ratio of the drilling fluid and/or the average specific gravity of the solids in the drilling fluid. For example, if both the oil-water ratio of the drilling fluid and the average specific gravity of the solids in the drilling fluid are determined, at least one property of the drilling fluid may be adjusted in response to both the determined oil-water ratio of the drilling fluid and the average specific gravity of the solids in the drilling fluid. The adjustment of the one or more properties of the drilling fluid in response to the one or more determined additional properties of the drilling fluid may be performed manually by an operator or automatically, for example, by a central processing unit in the fluid processing unit.

Referring now to fig. 3, an exemplary wellbore drilling assembly 100 that may be used in connection with the disclosed method is illustrated and generally designated by the reference numeral 100. It should be noted that although wellbore drilling assembly 100 is depicted in fig. 3 as an earth-based drilling assembly, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations employing floating or sea-based platforms and rigs without departing from the scope of the present disclosure.

As shown, the drilling assembly 100 may include a drilling platform 102, the drilling platform 102 supporting a derrick 104, the derrick 104 having a traveling block 106 for raising and lowering a drill string 108. As is well known to those skilled in the art, the drill string 108 may include, but is not limited to, drill pipe and coiled tubing. A kelly (kelly)110 supports the drill string 108 as the drill string 108 is lowered through a rotary table 112. A drill bit 114 is attached to the distal end of the drill string 108 and is driven by a downhole motor and/or rotated from the surface of the well via the drill string 108. As the drill bit 114 rotates, it creates a wellbore 116, which wellbore 116 penetrates various subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through a feed pipe 124 and to the kelly 110, which kelly 110 conveys the drilling fluid 122 downhole through the interior of the drill string 108 and through one or more orifices in the drill bit 114. The drilling fluid 122 is then circulated back to the surface via an annular space 126 defined between the drill string 108 and the wall of the wellbore 116. At the surface, the recirculated or used drilling fluid 122 exits the annular space 126 and may be conveyed to a fluid handling unit 128 via an interconnecting flow line 130. More than one fluid treatment unit may be used if necessary or desired. After passing through the fluid treatment unit 128, the "cleaned" drilling fluid 122 is deposited into a nearby holding pond 132 (also referred to as a mud pond).

One or more chemicals, fluids, and/or additives (e.g., weighting agents and fluid loss control additives) may be added to the drilling fluid 122 via a blending hopper 134, which blending hopper 134 is communicatively coupled to or otherwise in fluid communication with the holding reservoir 132. Mixing hopper 134 may include, but is not limited to, mixers and associated mixing equipment known to those skilled in the art. However, in other embodiments, one or more chemicals, fluids, and/or additives may be added to the drilling fluid 122 at any other location in the drilling assembly 100. In at least one embodiment, for example, there can be more than one holding cell 132, such as a plurality of holding cells 132 in series. Further, the holding reservoir 132 may represent one or more fluid storage facilities and/or units, where the disclosed chemicals, fluids, and/or additives may be stored, recovered, and/or conditioned until added to the drilling fluid 122.

For example, when used in conjunction with the methods disclosed herein, the drilling assembly 100 may be used to drill a wellbore penetrating a subterranean formation while circulating the drilling fluid 122 through the wellbore. The methods disclosed herein may also include measuring the specific heat capacity of the drilling fluid 122 and then determining one or more additional properties of the drilling fluid 122, including the oil-water ratio of the drilling fluid and/or the average specific gravity of the solids in the drilling fluid.

Although shown in fig. 3 as being disposed at the surface at the exit of the wellbore 116 through the annulus 126 and upstream of the mud retention reservoir 132, the fluid handling unit 128 may be disposed elsewhere in the drilling assembly 100 to facilitate its normal operation without departing from the scope of the present disclosure. For example, fig. 4 is the same as fig. 3, except that it depicts the fluid handling unit 128 as being located in a mud holding tank 132. For example, fig. 5 is the same as fig. 3 and 4, except that it depicts the fluid handling unit 128 as being downstream of the blending hopper 134.

Referring to fig. 6, a portion of the fluid handling unit 128 specifically related to the methods disclosed herein will be described in more detail. The fluid treatment unit 128 may also include other equipment (not shown), such as one or more shakers (e.g., shale shakers), centrifuges, hydrocyclones, separators (including magnetic separators and electric separators), deslimers, desanders, filters (e.g., diatomaceous earth filters), heat exchangers, and other types of fluid recovery equipment. Further, the fluid handling unit 128 may include one or more sensors and one or more meters, pumps, compressors, etc. for, for example, storing, monitoring, conditioning, and/or restoring any of the example chemicals, fluids, and additives disclosed herein. A plurality of fluid treatment units may be used, including some or all of the devices described above.

As shown in FIG. 6, portions of fluid processing unit 128 particularly relevant to the methods disclosed herein may include a specific heat capacity sensor ("SHCS") 136 and a computer and central processing unit ("CPU") 138. For example, the specific heat capacity sensor 136 measures the specific heat capacity of the drilling fluid 122. For example, the specific heat capacity sensor 136 may be a commercially available specific heat capacity probe.

The CPU 138 may be communicatively coupled to the SHCS 136 and receive signals from the SHCS 136 including the specific heat capacity of the drilling fluid for further processing. The CPU 138 may be configured to execute one or more sequences of instructions, programming sites, or code stored on a non-transitory computer readable medium. For example, the CPU 138 may include an electronic database and computer program that allows it to input the specific heat capacity measured by the SHCS 136 into the representation as described above, compare the measured specific heat capacity to a predetermined specific heat capacity of the representation, and select possible values of additional properties corresponding to the predetermined specific heat capacity that most closely matches the measured specific heat capacity of the drilling fluid. The CPU may also adjust one or more properties of the drilling fluid 122 based at least in part on the determined additional properties of the drilling fluid.

The fluid handling unit 128 may be configured to extract a sample from the drilling fluid 122 and measure the specific heat capacity of the sample. For example, specific heat capacity measurements may be made at elevated or reduced temperatures, elevated fluid pressures, or both. Thus, the fluid handling unit 128 may be a vessel that may be heated, pressurized, or both to perform specific heat capacity measurements of the drilling fluid 122.

The CPU 138 may be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a programmable logic device, a controller, a state machine, gated logic, discrete hardware components, an artificial neural network, or any similar suitable entity that can perform calculations or other manipulations of measured values and/or data. In some embodiments, the CPU 138 may also include elements such as: memory (e.g., Random Access Memory (RAM)), flash memory, read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read-only memory (EPROM)), registers, a hard disk, a removable disk, a CD-ROM, a DVD, or any other similar suitable storage device or medium.

As used herein, a machine-readable medium shall refer to any medium that provides instructions, directly or indirectly, to CPU 138 for execution. A machine-readable medium may take many forms, including for example, non-volatile media, and transmission media. Non-volatile media may include, for example, optical and magnetic disks. Volatile media may include, for example, dynamic memory. Transmission media may include, for example, coaxial cables, fiber optics, and the like that form a bus. Common forms of machine-readable media may include, for example, a floppy disk (floppy disk), a flexible disk, hard disk, magnetic tape, other similar magnetic media, CD-ROM, DVD, other similar optical media, punch cards, paper tape with patterned holes, and similar physical media, a RAM, a ROM, a PROM, an EPROM, and a flash EPROM.

For example, the CPU 138 may be configured to perform or reference mathematical calculations, look-up tables, and offset well data comparisons stored on the CPU 138 to derive oil-to-water ratios, average specific gravity of solids, or both. In some cases, the CPU 138 may output numerical values, graphs, etc. indicative of one or more properties of the drilling fluid 122, including, but not limited to, the oil-to-water ratio of the drilling fluid and/or the average specific gravity of the solids in the drilling fluid. In some cases, the CPU 138 may adjust or recommend adjusting the composition of the drilling fluid 122 (e.g., adding additional weighting agents), drilling operation parameters (e.g., increasing or decreasing permeability and weight-on-bit), or both, based on derived one or more properties of the drilling fluid 122, including but not limited to oil-to-water ratio, average specific gravity of derived solids, or both.

Thus, the methods disclosed herein utilize the specific heat capacity of the circulating drilling fluid to quickly and easily determine additional properties of the drilling fluid, such as the oil-to-water ratio of the drilling fluid and the average specific gravity of the solids in the drilling fluid. For example, the disclosed methods may be performed continuously, in real time, or at least frequently on a periodic basis (e.g., every half hour when performing a drilling process). For example, the specific heat capacity may be measured and one or more additional properties of the drilling fluid may be determined within 5 minutes or 10 minutes. The specific heat capacity of the circulating drilling fluid can be measured as the drilling fluid exits the wellbore or is placed back into the wellbore.

Any of the exemplary chemicals, fluids, and additives disclosed herein may directly or indirectly affect one or more components or parts of the apparatus associated with the preparation, delivery, recapture, recycle, reuse, and/or disposal of any of the disclosed chemicals, fluids, and additives. For example, any of the disclosed chemicals, fluids, and additives may directly or indirectly affect one or more components or parts of equipment associated with the example wellbore drilling assembly 100.

For example, any of the disclosed chemicals, fluids, and additives may directly or indirectly affect one or more fluid treatment units 128, which one or more fluid treatment units 128 may include, but are not limited to, one or more shakers (e.g., shale shakers), centrifuges, hydrocyclones, separators (including magnetic and electric separators), deslimers, desanders, filters (e.g., diatomaceous earth filters), heat exchangers, and other types of fluid recovery equipment. In addition to the one or more specific heat capacity sensors, as described above, the one or more fluid processing units 128 may also include one or more other sensors and one or more meters, pumps, compressors, etc. for, for example, storing, monitoring, conditioning, and/or restoring any of the example chemicals, fluids, and additives disclosed herein.

Any of the disclosed chemicals, fluids, and additives may directly or indirectly affect the pump 120, the pump 120 typically including any conduit, line, truck (truck), tubing, and/or piping used to transport the chemicals, fluids, and additives downhole in a fluid, any pump, compressor, or motor (e.g., an upper layer motor or a downhole motor) used to drive the movement of the chemicals, fluids, and additives, any valve or associated fitting used to regulate the pressure or flow rate of the chemicals, fluids, and additives, and any sensor (i.e., pressure sensor, temperature sensor, flow sensor, etc.), gauges, and/or combinations thereof, and the like. The disclosed chemicals, fluids, and additives may also directly or indirectly affect the mixing hopper 134 and holding tank 132 and their various changes.

Any of the disclosed chemicals, fluids, and additives may also directly or indirectly affect various downhole equipment and tools that may come into contact with the chemicals, fluids, and additives, such as, but not limited to, the drill string 108, any float, collar, mud motor, downhole motor, and/or pump associated with the drill string 108, and any MWD/LWD tool associated with the drill string 108 and associated telemetry equipment, sensors, or distributed sensors. Any of the disclosed chemicals, fluids, and additives may also directly or indirectly affect any downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, and other wellbore isolation devices or components, etc., associated with wellbore 116. Any of the disclosed chemicals, fluids, and additives may also affect, directly or indirectly, the drill bit 114, which may include, but is not limited to, roller cone drill bits, PDC drill bits, natural diamond drill bits, any open-hole drill bits, reamers, core bits, and the like.

Although not specifically illustrated herein, any of the disclosed chemicals, fluids, and additives may also directly or indirectly affect any transportation or delivery equipment used to convey the chemicals, fluids, and additives to drilling assembly 100, such as any transportation containers, conduits, lines, trucks, tubulars, and/or pipes used to fluidly move the chemicals, fluids, and additives from one location to another, any pumps, compressors, or motors used to drive the movement of the chemicals, fluids, and additives, any valves or associated joints used to regulate the pressure and flow rate of the chemicals, fluids, and additives, and any sensors (i.e., pressure and temperature sensors), gauges, and/or combinations thereof, and the like.

The method of the invention is therefore well adapted to attain the ends and advantages mentioned, as well as those inherent therein. The particular examples disclosed above are illustrative only, as the present methods may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present method. Although the methods are described in terms of "comprising," "including," "having," or "including" various components or steps, in some examples, the methods may also "consist essentially of or" consist of the various components and steps. Furthermore, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.