ENVIRONMENTAL MATERIAL

FIELD

[0001] The present technology is directed to a system and method for measuring fluid properties. In particular, the present technology involves a system and method provided with a drill string for determining various downhole properties.

BACKGROUND

[0002] Drilling operations in oil and gas exploration involves the use a drilling fluid, such as drilling mud including one or more individual components. During drilling operations, the environmental conditions of the subterranean formation being drilled can alter the properties of the drilling fluid and/or the individual components and the subterranean formation can release gas that become dissolved within the drilling fluid. The alteration of the drilling fluid and/or individual components can require changes to drilling operations to maintain safe and efficient operations.

BRIEF DESCRIPTION OF THE DRAWINGS

[0003] The embodiments herein may be better understood by referring to the following description in conjunction with the accompanying drawings in which like reference numerals indicate analogous, identical, or functionally similar elements. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0004] FIG. 1 is a schematic diagram of a tubular string provided in a wellbore during a drilling process according to the present disclosure;

[0005] FIG. 2 is a diagrammatic view of a mud density system according to the present disclosure;

[0006] FIG. 3 is a plot of gas solubility within a fluid according the present disclosure;

[0007] FIG. 4 is a plot of formation volume fraction for a fluid according to the present disclosure;

[0008] FIG. 5 depicts a block diagram of an exemplary device in accordance with certain embodiments of the present disclosure.

DETAILED DESCRIPTION

[0009] Various embodiments of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure. Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims, or can be learned by the practice of the principles set forth herein.

[0010] The present disclosure is drawn to a method of determining drilling fluid density with dissolved contamination. During one or more drilling operations, a drilling fluid may become contaminated with one or more contaminates. The method can involve continuously monitoring fluid density, including changes in fluid density due to the presence of contaminants therein, thereby allowing for real-time adjustment of one or more drilling operation parameters. The method can include positioning one or more sensors with a wellbore, the one or more sensors operable to measure one or more characteristics of the drilling fluid within the wellbore. The one or more characteristics of the fluid can be at least one of temperature and/or pressure and the fluid can include one or more individual components. A gas solubility value and a volume formation factor for each of the one or more individual components can be obtained based on the measured one or more characteristics. A formation gas modified volume can be calculated using the volume formation factor for each of the one or more individual components. The formation gas modified volume can include the volume change caused by the dissolution of one or more gases from the surrounding environment into the fluid. A total mass of the drilling fluid can be determined using the mass of the one or more individual components and a mass of dissolved gas, and a formation gas modified density can be determined based on the total mass and the formation gas modified volume.

[0011] The method can adjust one or more drilling operations or drilling operation parameters in response to the measured properties including the change in drilling fluid density (for instance, formation gas modified density of the fluid).

[0012] The method disclosed herein can be implemented with a drilling system including a drill string in which the method can be operated at the surface, remotely, or in real time within the drill string itself.

[0013] One or more sensors can be placed downhole to measure, in real time, one or more drilling fluid properties. The drilling fluid properties can be selected from density, viscosity and/or volumetric fraction. The measured drilling fluid properties can be used to calculate one or more parameters, such as gas solubility, formation factor etc. The one or more parameters can be utilized to calculate a change in drilling fluid density as a result of contamination by the wellbore environment.

[0014] Drilling fluid and the components therein can be optimized for drilling operations with particular wellbores, wellbore location, and/or subterranean formations. The change of drilling fluid density during drilling operations contaminates can negatively affect drilling operations; reduce safety, performance and/or efficiency. During drilling operations, the system can monitor changes in drilling fluid density and adjust one or more drilling operation parameter in response to detected changes in drilling fluid density. The system can maintain, in real time, optimum drilling operations, safety, performance, and/or efficiency as the drilling fluid density changes due to contamination from the wellbore and/or subterranean formation.

[0015] FIG. 1 is a schematic diagram depicting an environment in which the present disclosure may be implemented. While FIG. 1 illustrates a land-based environment, the present disclosure may be equally implemented in a sea-based environment. The land-based drilling system 100 can include a drill string 10 can have a longitudinal length 55 formed by one or more tubulars 12. The drill string 10 can have a drill bit 14 at a distal end 16 of the longitudinal length 55. The drill bit 14 can form a bore 18 through a subterranean formation 50. In some instances, the bore 18 can be a wellbore for use in oil and gas drilling operations to recover hydrocarbons from the subterranean formation 50.

[0016] Further, while FIG. 1 details a substantially vertically extending bore, it is within the scope of this disclosure to implement the method and/or system in a vertical extending bore, horizontally extending bore, or any combination thereof.

[0017] The drill string 10 can have one or more sensors 102 disposed along the one or more tubulars 12 or drill bit 14. The one or more sensors 100 can measure properties of fluid 20 within the bore 18 and surrounding the one or more tubulars 12 or the drill bit 14. The fluid properties can include, but is not limited to, density, viscosity and/or volumetric fraction of each component at different pressures and temperatures. The one or more sensors 102 can be coupled with one or more tubulars 12 of the drill string 10 and/or be integrally formed therein. The one or more sensors 102 can also be coupled with the drill bit 14 and/or integrally formed therein. In at least one instance, the drill string 10 includes one or more sensors 100 coupled with the one or more tubulars and one or more sensors 102 coupled with the drill bit 14.

[0018] The one or more sensors 102 can be communicatively coupled with a fluid density system 200 operable to determine density of the fluid 20 at the measured fluid properties within the bore 18. The fluid density device 206 can be disposed at the surface 5, locally at the drill string 10 including drill bit 14 and transmit data to a local device, or remotely to an off-site facility monitoring drilling operations. The one or more sensors 102 can communicatively couple with the fluid density device 200 through a wired connection or via a wireless connection, or a combination thereof.

[0019] The fluid 20 within the bore 18 can be a drilling fluid (for example, drilling mud) including a plurality of individual components. The plurality of individual components of the fluid within the bore 18 can include, but is not limited to, diesel, synthetic oil, water, brine, emulsifiers, solids, paraffins, etc. Each of the individual components can respond differently to changes in temperature and pressure as the bore 18 extends into the subterranean formation 50. Specifically, changes in compressibility, volume, and/or density of the individual components of the fluid 20 at various pressures and temperatures within the bore 18 can significantly alter drilling operations.

[0020] During drilling operations, such as those illustrated in FIG. 1, the subterranean formation 50 may release one or more gases, such as methane, that may become dissolved within the one or individual components of the fluid 20. The entry and/or dissolution of one or more gases into the fluid 20 can change the equivalent circulating density (ECD) and/or viscosity of the one or more individual components and/or the fluid 20. The change in ECD and/or viscosity of the fluid 20 can require adjustment of the drilling operations to maintain safe operations without damaging the drill string 10, bore 18, and/or the subterranean formation 50.

[0021] The adjustment of the drilling operations and operation parameters can include, but is not limited to, changing rotational speed of the drill bit and/or drillstring 10, adjusting the backpressure at the surface, altering the drilling fluid being used, changing the pump rate, or any other know drilling parameter.

[0022] The fluid density device 206 and one or more sensors 102 coupled therewith can be implemented to with numerous drilling operations including, but not limited to, managed pressured drilling (MPD), under-balanced drilling (UBD), overbalanced drilling (OBD), measurement while drilling (MWD), logging while drilling, drilling automation, well control operation, or any combination thereof to provide more detailed information of fluid properties within the bore 18 and their respective effects on drilling operations to provide a safer, more efficient drilling operation. The use of the drilling system 100 during drilling operations can help determine bottomhole pressure and fluid changes during drilling operations, leading to a reduction in non-productive time (NPT).

[0023] The determined bottomhole pressure can allow the drilling system to manage pressure control to keep bottomhole pressure above formation pressure (i.e. overbalanced drilling). The system can further calculate a minimum volumetric correction plan and a surface pressure modulation plan to circulate dissolved gas out of the bore while increasing fluid density to restore hydrostatic pressure above formation pressure.

[0024] In at least one instance, the drilling system 100 can be an oil and gas drilling system forming a wellbore 18 through a subterranean formation 50 for recovering hydrocarbons. The one or more sensors 102 can be measure the pressure and/or temperature of drilling fluid (for example, drilling mud) used within the wellbore 18 during drilling operations. The drilling system 100 can be implemented with any drilling mud and/or drilling mud mixture used in the oil and gas industry.

[0025] While FIG. 1 illustrates a land-based drilling operation, the method and drilling fluid system as disclosed herein can be similarly implemented in a sea-based drilling operation without deviating from the scope.

[0026] FIG. 2 illustrates a diagrammatic view of a drilling fluid system 200. The drilling fluid system 200 can include one or more sensors 202 coupled with a drilling apparatus 204. The drilling apparatus 204 can include a drill string, one or more tubulars, and/or a drill bit, or any combination thereof. The one or more sensors 202 can be disposed along the drilling apparatus 204 or integrally formed therewith and communicatively coupled with a fluid density device 206. The one or more sensors 202 can be communicatively coupled, via a wired or wireless connection, with the fluid density device 206. The one or more sensors 202 can be operable to measure one or more characteristics of a fluid adjacent to the one or more sensors 202. The fluid can include one or more individual components collectively forming a singular fluid. The one or more characteristics of the fluid can include at least temperature and/or pressure.

[0027] The fluid density device 206 can include one or more storage devices 208 and at least one processor 210. The fluid density device 206 can be communicatively coupled with the one or more sensors 202 to receive the measured one or more characteristics of the fluid. The one or more storage devices 208 of can storage information relating to properties for each the one or more individual components at varying temperature and/or pressure conditions. The properties for each of the one or more individual components at varying temperature and/or pressure conditions can be determined in a controlled environment to determine changes in volume, viscosity, and/or gas solubility and stored in the one or more storage devices 208. The one or more storage devices 208 can store properties for any number of individual components, including components not being utilized in the fluid at a particular time.

[0028] The one or more storage devices 208 can be locally accessible storage devices such as one or more hard disk drives (HDDs), solid state drives (SSDs), flash memory, or a remotely operated and managed storage device (for example, server, cloud storage, etc.).

[0029] The one or more storage devices 208 can also store information relating to the gas solubility (R _s ) of each of the one or more individual components. The gas solubility (R _s ) can defined as a ratio of volume of dissolved gas in a standard condition within the individual components to volume of the individual component at standard condition. The gas solubility (R _s ) can be represented by equation (1) below:

ySTC

_ dg

(1) R _s ySTC

[0030] Where V^ ^c is the volume of dissolved gases in the individual component at standard conditions and V ^STC is the volume of the individual component at standard conditions. Similarly, the gas solubility (R _s ) can be determined at various predetermined pressure and temperature conditions and fit with an empirical correlation and stored within the one or more storage devices 208. The gas solubility (R _s ) can be calculated in real-time, or can be pre-calculated for a range of predetermined conditioned and subsequently accessed upon receipt of a measured temperature and/or pressure by the one or more sensors 202. The fluid density device 206 can access, from the one or more storage devices, the gas solubility (R _s ) of a particular individual component of the fluid at a measured temperature and pressure.

[0031] In at least one instance, during a wellbore drilling operation gases (for example, methane (CH ₄ ), and ethane (C ₂ H ₆ )) are expected to become dissolved within the drilling fluid along with impurities (for example, carbon dioxide (C0 ₂ ), nitrogen (N ₂ ), hydrogen sulfide (H ₂ S)).

[0032] The fluid density device 206 can determine (for example, access a pre-calculated value from one or more storage devices) the gas solubility (R _s ) for any number of individual components within the fluid, specifically the individual components in a liquid phase. The gas solubility (R _s ) can be assumed to be substantially zero for any individual component(s) of the fluid as inert.

[0033] The known gas solubility (R _s ) of the one or more individual components within the fluid can allow the fluid density device 206 to determine the temperature and/or pressure at which the gas will begin to break out as a separate phase. The drilling system 100 can adjust one or more drilling operation parameters in response to the determined gas separation temperature and/or pressure.

[0034] The one or more storage devices 208 can also store information relating to a volume formation factor (B) of each of the one or more individual components of the fluid at varying temperatures and pressures. The volume formation factor (B) can describe the volume difference of an individual component in measured (for example, downhole) condition and at a standard (for example, surface) condition. The volume formation factor (B) can be represented by equation (2) below:

_V RC

(2) B = i JsTC

[0035] Where V ^RC is volume of the individual component with at the measured conditions and can include a predetermined amount of gas dissolved therein and V ^STC is the volume of the individual component under standard conditions. The volume in the measured condition can include gas dissolved therein, while also accounting for total volume change due to changes in temperature and pressure. The total volume change can be determined at various predetermined pressure and temperature conditions with varying amounts of gas dissolved therein. An empirical correlation can be fit to the calculated total volume changes and stored within the one or more storage devices 208. The fluid density device 206 can access, from the one or more storage devices 208, the volume formation factor (B) of a particular individual component of the fluid at a temperature and pressure measured by the one or more sensors 202.

[0036] The fluid density device 206 can determine volume formation factor (B) for any number of individual components within the fluid, specifically the individual components in a liquid phase. The volume formation factor (B) can be assumed to be substantially one (B=l) for any individual component(s) of the fluid as a solid.

[0037] In at least one instance, the fluid can be comprised of up to 40% of solid particles (for example, barite). The individual components in a solid phase are generally considered inert, in which the mass and volume do not change with external conditions, such as temperature and pressure. The absolute volume of base fluid or emulsion is reduced meaning fluids with higher solid content are less susceptible to changes in volume as environmental conditions change (for example, temperature and pressure).

[0038] The fluid density device 206 and the at least one processor 210 can be operate to determine total volume changes for each individual component of the fluid by determining the appropriate R _s and B value based on the one or more conditions measured by the one or more sensors 202. The total volume change for the fluid at the operating conditions can be determined by a multiplying the fluid volume at standard condition (for example, surface conditions) by a summation of a volume formation factor multiplied by a volume fraction for each of the individual components. The total volume change can be represented by equation (3) below:

[0039] In equation (3), Bi is the volume formation factor for the individual component at the measured properties of the fluid, and a. is the volume fraction of the individual component relative to the fluid. The total volume change can be the formation gas modified volume which can include one or more gases dissolved within the fluid (and/or one or more components).

[0040] The fluid density device 206 and the at least one processor 210 can determine the total mass accounting for the gas dissolved within the fluid. The total mass can be represented as equation (4) below:

[0041] In equation (4), mi is the mass for the individual component and ni _dg is the mass of dissolved gas. The fluid density device 206 and the at last one processor 210 can calculate the new fluid density (p) using the new volume and new mass as determined by equation (3) and equation (4), respectively. The new density (p) equation can be represented as by equation (5) below:

[0042] The new density can represent the formation gas modified density. The formation gas modified density can be the density of the fluid with the one or more gasses dissolved therein. The fluid density device 206 and the one or more storage devices 208 can access and store information relating to a plurality of individual components commonly used or implemented within drilling fluids. In calculating the new density (p), the fluid density device 206 can assume solid components (for example, barite) within the fluid are not affected by changes in temperature and/or pressure. The fluid density device 206 can further ignore reactions between individual components of the fluid, thus assuming the individual components of the fluid behave identically separately and combined.

[0043] The drilling fluid system 200 can use the new density (p) (for example, formation gas modified density) to make operational decisions during drilling operations including, but not limited to, rotational speed (for example, revolutions per minute (rpm)), choke position for adjusting backpressure, drilling fluid, drilling fluid flow rate, etc. The fluid density device 206 and the at least one processor 210 can communicatively couple with the drilling apparatus 204 to make one or more operational changes in the drilling operations in view of the changes in density to the fluid adjacent to and/or surrounding the drilling apparatus 204.

[0044] In at least one instance, the fluid density device 206 can determine the changes in density of a drilling fluid due to changes in temperature, pressure, and/or the dissolution of formation gas into the drilling fluid and adjust the backpressure of the drilling apparatus to maintain drilling operations within proper safety ranges. The fluid density device 206 can further determined changes to compressibility and/or viscosity of the drilling fluid due to changes in temperature, pressure, and/or dissolution of formation gas into the drilling fluid. The fluid density device 206 can determine a formation gas modified compressibility of the drilling fluid. The formation gas modified compressibility can be determined using the formation gas modified volume. The fluid density device 206 can determine formation gas modified viscosity of the drilling fluid.

[0045] FIG. 3 illustrates an example of methane solubility in selective base oils or base oil components for determining gas solubility according to the present disclosure. The gas solubility (R _s ) of methane varies as temperature and/or pressure changes. The drilling fluid system 200 can implement one or more gas solubility charts (for example, methane solubility as detailed in FIG. 3) in the one or more storage devices 208. The gas solubility (R _s ) can be determined in a controlled environment at a plurality of predetermined environmental conditions and an empirical fit can then be applied to interpolate measures falling between predetermined environmental conditions. The measured conditions along with the empirical fit and/or interpolations can be stored in the one or more storage devices 208 of the drilling fluid system 200 shown in FIG. 2. The one or more storage devices 208 can include measured data for any number of individual components (for example, diesel, oil, water, brine, glycols, glycerin, NaCl brines, calcium chloride brines cesium formate brines, formate brines (potassium, sodium and calcium), sea water, potassium chloride brines, bromide brines (sodium, calcium and zinc), etc.) and for any number of individual gas solubility (for example, methane, ethane, carbon dioxide, nitrogen, hydrogen sulfide, etc.).

[0046] As illustrated in FIG. 3, a plurality of individual components changes under various conditions can be pre-calculated in a controlled setting. While FIG. 3 plots individual components mineral oil, linear paraffin, n-paraffin, no.2 diesel, n-paraffin (SPE 91009), and ester, it is within the scope of this disclosure to include any individual components within the drilling fluid system 200. The drilling fluid system 200 can be operated to store and/or receive information relating to any individual component for use with a drilling operation.

[0047] FIG. 4 illustrates an example formation volume factor correlation in oil based mud according to the present disclosure. The formation volume factor relates density and volume of the fluid (drilling fluid and dissolved gas), and free gas components to given pressure and temperature condition. The concept of formation volume factor was initially used for oil and gas mixture, but it can be extended to any soluble gas and liquid mixture. The formation volume factor (B) for one or more individual components with varying gas solubility (Rs) at measured properties can be determined in a controlled setting, and an empirical fit or interpolation can be used to determine values falling between predetermined measured conditions. The formation volume factor (B) can be stored on the one or more storage devices 208 within the drilling fluid system 200 of FIG. 2. While FIG. 4 illustrates a formation volume factor for oil-based mud (B _mud ) for methane dissolved in diesel, it is within the scope of the disclosure for any number of individual components formation volume factor (B) to be calculated in data table or empirical correlations with any number of gasses dissolved therein.

[0048] FIG. 5 is a block diagram of an exemplary device 500 which may be employed to implement the disclosure herein to determine density of a fluid. Device 500 is configured to perform processing of data and communicate with the one or more sensors associated with fluid density device 200 and/or communicatively coupled with fluid density device 206. As shown, device 500 includes hardware and software components such as network interfaces 510, at least one processor 520, sensors 560 and a memory 540 interconnected by a system bus 550. The storage devices 208 described above may be the memory 540 and/or processor 210 described may be the processor 520. Network interface(s) 510 include mechanical, electrical, and signaling circuitry for communicating data over communication links, which may include wired or wireless communication links. Network interfaces 510 are configured to transmit and/or receive data using a variety of different communication protocols, as will be understood by those skilled in the art.

[0049] Processor 520 represents a digital signal processor (e.g., a microprocessor, a microcontroller, or a fixed-logic processor, etc.) configured to execute instructions or logic to perform tasks in a wellbore environment. Processor 520 may include a general purpose processor, special-purpose processor (where software instructions are incorporated into the processor), a state machine, application specific integrated circuit (ASIC), a programmable gate array (PGA) including a field PGA, an individual component, a distributed group of processors, and the like. Processor 520 typically operates in conjunction with shared or dedicated hardware, including but not limited to, hardware capable of executing software and hardware. For example, processor 520 may include elements or logic adapted to execute software programs and manipulate data structures 545, which may reside in memory 540.

[0050] Sensors 560 typically operate in conjunction with processor 520 to perform wellbore measurements, and can include special-purpose processors, detectors, transmitters, receivers, and the like. In this fashion, sensors 560 may include hardware/software for generating, transmitting, receiving, detection, logging, and/or sampling magnetic fields, seismic activity, and/or acoustic waves, or other well parameters. [0051] Memory 540 comprises a plurality of storage locations that are addressable by processor 520 for storing software programs and data structures 545 associated with the embodiments described herein. An operating system 542, portions of which may be typically resident in memory 540 and executed by processor 520, functionally organizes the device by, inter alia, invoking operations in support of software processes and/or services 544 executing on device 500. These software processes and/or services 544 may perform processing of data and communication with device 500, as described herein. Note that while process/service 544 is shown in centralized memory 540, some embodiments provide for these processes/services to be operated in a distributed computing network.

[0052] It will be apparent to those skilled in the art that other processor and memory types, including various computer-readable media, may be used to store and execute program instructions pertaining to the fluid evaluation techniques described herein. Also, while the description illustrates various processes, it is expressly contemplated that various processes may be embodied as modules having portions of the process/service 544 encoded thereon. In this fashion, the program modules may be encoded in one or more tangible (non-transitory) computer readable storage media for execution, such as with fixed logic or programmable logic (e.g., software/computer instructions executed by a processor, and any processor may be a programmable processor, programmable digital logic such as field programmable gate arrays or an ASIC that comprises fixed digital logic. In general, any process logic may be embodied in processor 520 or computer readable medium encoded with instructions for execution by processor 520 that, when executed by the processor, are operable to cause the processor to perform the functions described herein.

[0053] The embodiments shown and described above are only examples. Even though numerous characteristics and advantages of the present technology have been set forth in the foregoing description, together with details of the structure and function of the present disclosure, the disclosure is illustrative only, and changes may be made in the detail, especially in matters of shape, size and arrangement of the parts within the principles of the present disclosure to the full extent indicated by the broad general meaning of the terms used in the attached claims. It will therefore be appreciated that the embodiments described above may be modified within the scope of the appended claims. STATEMENT BANK:

Statement 1: A method of determining drilling fluid density with dissolved contamination fluid, the method comprising positioning one or more sensors within a wellbore, the one or more sensors operable to measure one or more characteristics of a fluid within the wellbore, the one or more characteristics of the fluid being at least one of temperature and a pressure, wherein the fluid comprises one or more individual components, obtaining a gas solubility value and a volume formation factor for the one or more individual components of the fluid based on the measured one or more characteristics, calculating a formation gas modified volume of the drilling fluid using the volume formation factor and a volume fraction for each of the one or more individual components, determining a total mass of the drilling fluid using the mass of the one or more individual components and a mass of dissolved gas, and determining a formation gas modified density of the drilling fluid based on the total mass and the formation gas modified volume.

Statement 2: The method of Statement 1, further comprising determining a temperature and/or a pressure within the wellbore at which the dissolved gas within the one or more individual components of the fluid separates.

Statement 3: The method of Statement 1 or Statement 2, further comprising adjusting one or more operation parameter to maintain bottomhole pressure above formation pressure.

Statement 4: The method of any one of Statements 1-3, further comprising adjusting one or more drilling operation parameters based on the determined formation gas modified density.

Statement 5: The method of any one of Statements 1-4, wherein the volume formation factor is calculated for each of the one or more individual components of the fluid in a liquid phase.

Statement 6: The method of any one of Statements 1-5, wherein the gas solubility value of the one or more individual components is a ratio of a volume of dissolved gas within one of the one or more individual components to the volume of the individual component. Statement 7: The method of any one of Statements 1-6, further comprising determining a formation gas modified viscosity of the drilling fluid.

Statement 8: The method of any one of Statements 1-7, further comprising determining a formation gas modified compressibility of the drilling fluid.

Statement 9: A drill system comprising one or more sensors positioned within a wellbore, the one or more sensors operable to measure one or more characteristics of a fluid within the wellbore, the one or more characteristics of the fluid being at least one of temperature and a pressure, a drilling string disposed within the wellbore, at least portion of the drill string rotatable relative to the wellbore, one or more storage devices, the storage device storing gas solubility values and volume formation factors for a plurality of individual components in a liquid phase, one or more processors coupled with the drill string, the processor operable to obtain, from the one or more storage devices, a gas solubility value and a volume formation factor for one or more individual components of the fluid at the measured one or more characteristics, calculate a formation gas modified volume of the fluid using the volume formation factor and a volume fraction for each of the one or more individual components, determine a total mass of the fluid using the mass of the one or more individual components and a mass of dissolved gas within each of the one or more individual components, and determine a formation gas modified density of the fluid from the total mass and the formation gas modified volume.

Statement 10: The drill system of Statement 9, wherein the volume formation factor is calculated for each of the one or more individual components disposed within the fluid in a liquid phase.

Statement 11: The drill system of Statement 9 or Statement 10, wherein the gas solubility value of the one or more individual components is a ratio of a volume of dissolved gas within one of the one or more individual components to the volume of the individual component.

Statement 12: The drill system of any one of Statements 9-11, further comprising determining a formation gas modified viscosity of the drilling fluid. Statement 13: The dill system of any one of Statements 9-12, further comprising determining a formation gas modified compressibility of the drilling fluid.

Statement 14: The drill system of any one of Statements 9-13, wherein the one or more storage devices are remotely located storage devices.

Statement 15: The drill system of any one of Statements 9-14, wherein the one or more storage devices are cloud-based.

Statement 16: The drill system of any one of Statements 9-15, wherein the gas solubility value and the volume formation factor for the one or more individual components is calculated in a controlled environment.

Statement 17: The drill system of any one of Statements 9-16, wherein the gas solubility value and the volume formation factor for the one or more individual components is interpolated from one or more values calculated at predetermined conditions.

Statement 18: The drill system of any one of Statements 9-17, wherein rotation of the drill string can be adjusted based at least in part on the determined formation gas modified density of the fluid.

Statement 19: The drill system of any one of Statements 9-18, wherein one or more drilling operation parameters are adjusted based on the determined formation gas modified density

Statement 20: The drill system of any one of Statements 9-18, wherein a backpressure can be adjusted based on the determined formation gas modified density of the fluid.

Statement 21: A drilling apparatus comprising a drilling device, at least a portion of the drilling device rotatable relative to a longitudinal axis of the drilling device, one or more sensors positioned along the drilling device, the one or more sensors operable to measure one or more characteristics of a fluid, the one or more characteristics of the fluid being at least one of temperature and a pressure, one or more storage devices communicatively coupled with the drilling device, the storage device storing gas solubility values and volume formation factors for a plurality of individual components in a liquid phase, one or more processors communicatively coupled with the drilling device, the one or more processors operable to: obtain, from the one or more storage devices, a gas solubility value and a volume formation factor for one or more individual components of the fluid at the measured one or more characteristics, calculate a formation gas modified volume of the fluid using the volume formation factor and a volume fraction for each of the one or more individual components, determine a total mass of the fluid using the mass of the one or more individual components and a mass of dissolved gas within each of the one or more individual components, and determine a formation gas modified density of the fluid from the total mass and the formation gas modified volume.

Statement 22: The drill apparatus of Statement 21, wherein the volume formation factor is calculated for each of the one or more individual components disposed within the fluid in a liquid phase.

Statement 23: The drill apparatus of Statement 21 or Statement 22, wherein the gas solubility value of the one or more individual components is a ratio of a volume of dissolved gas within one of the one or more individual components to the volume of the individual component.

Statement 24: The drill apparatus of any one of Statements 21-23, further comprising determining a formation gas modified viscosity of the drilling fluid.

Statement 25: The drill apparatus of any one of Statements 21-24, wherein one or more drilling operation parameters are adjusted based on the determined formation gas modified density