Untitled record

Full description, sister’s background

During oil and gas exploration, many types of information can be collected and analyzed. The information can be used to determine the quantity and quality of hydrocarbons in a reservoir and to develop or modify hydrocarbon production strategies. For example, the information can be used to evaluate storage, ensure flow,

<p dir="rtl">5 Storage simulation, facility optimization, production improvement strategies, and reserve evaluation. One relevant information control technique involves obtaining and analyzing fluid samples from a reservoir of interest. There are a range of different tools that can be used to obtain a sample of a fluid. The fluid sample can then be analyzed to determine fluid properties, including, but not limited to, composition concentration, molecular weight, molecular weight distribution, gas and oil ratios, point</p>

<p dir="rtl">10 Bubbling, dew point, phase envelope, viscosity, and combinations thereof, or the like. Conventional analysis requires transporting fluid samples to a laboratory for analysis. Downhole fluid sample analysis can also be used to provide fluid properties in real time, avoiding the delays associated with laboratory analysis. Surface analysis can also be used at the well site to provide real-time fluid properties without the need to transport fluid samples to a laboratory. However, accurate determination of fluid properties may be difficult</p>

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The actual time is limited in certain circumstances, for example during the early stages of field development (e.g., exploration/appraisal) when limited or even potentially no data are available.

General description of the invention

<p dir="rtl">5 Disclosed here are methods and systems for determining fluid properties in fluid samples issued by a downhole fluid sampling instrument. Determination of fluid properties may include determining the concentrations of components, including the concentration of the non-agglomerating component. For example, the concentration of the non-clumping component could include a mole distribution of the components of the fluid sample, including additional fractions (e.g., C6+) that would naturally clump together. Methods could include</p>

<p dir="rtl">10 Systems can also produce pressure, volume, and temperature properties (e.g., bubble point, phase envelop prediction, and so on) of fluid samples based on determining fluid properties. As discussed in more detail below, methods and systems for determining properties of the fluid can be used Fluid distribution function with an equation of state to determine the composition of fluid components in fluid samples. Inputs can include, but not limited to, downhole fluid sample measurements</p>

<p dir="rtl">15 confinement, gas-oil ratio, live oil density, and/or popping point.</p>

It may be preferable to determine the characteristics of reservoir fluids in a number of cases. Reservoir fluids may contain a number of different components, including hydrocarbons and non-hydrocarbons, with different molecular weights, which may make it difficult to accurately determine the real-time concentration of the components. Sample measurements can be taken

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Reservoir fluids can provide concentrations of the components, which are typically provided in a composition in which light hydrocarbons are agglomerated with heavy hydrocarbons (C6+, C5+, and so on). For example, the concentration of the components can be provided with the dioxide fractions shown Carbon dioxide (CO2), methane (CH4), ethane (C2H6), propane

<p dir="rtl">5 (C3H8), butane (C4H10), pentane (C5H12) and the C6+ alkane group.</p>

A C6+ group may include a concentration of all hydrocarbons with six or more carbon atoms agglomerated into a single component concentration. In some cases, the C5 hydrocarbons may not be reported separately, with the C5+ hydrocarbon group clumping into a single component concentration. Furthermore, some minor hydrocarbons, such as C4, C3, or C5 hydrocarbons, can also be grouped and stated

<p dir="rtl">10 Together, for example, a C3-C4 hydrocarbon group, a C3-C5 hydrocarbon group, and/or</p>

C4-C5 hydrocarbon group. These quantities can be stated as percentages by weight or moles.

However, there may be a need to separate the lumped component concentration, for example, to provide a non-lumped component concentration. Using the concentration of non-agglomerating components, pressure, volume, and temperature properties can be determined (e.g.

<p dir="rtl">15 bubble point, phase envelope prediction, and so on) for a fluid sample, which may be more accurate than if the concentration of agglomerated components were used, or another technique was used to make this determination. By having the fluid properties mentioned, the information can be used to determine the quantity and quality of hydrocarbons in a storage tank. To develop or modify hydrocarbon production strategies, methods and systems for determining fluid properties are disclosed that can provide concentrations of components, including concentrations of non-containing components.</p>

<p dir="rtl">20 Agglomerated, from the concentration of an agglomerated component. The composition of non-agglomerating components can include molar distribution</p>

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of components, including additional parts (for example, C5, C6+), which can

They are then used to determine additional fluid properties, such as pressure, volume, and temperature.

Brief explanation of the drawings

These drawings illustrate certain aspects of certain embodiments of the present invention, and should not be used for limitation

<p dir="rtl">5 Of or determine the sister invent.</p>

Figure 1 is a schematic diagram of an illustrative tool for sampling downhole fluid on a cable

holes.

Figure 2 is a schematic diagram of an illustrative downhole fluid sampling tool on a string

Drill pipes.

10

15

Figure 3 is a flowchart of an illustrative method for determining the properties of a fluid.

Figure 4 is a graph of the mole fraction distribution of one carbon atom for different live oil samples, with the table showing a zoomed-in view of components ranging from C5 to C36 and above.

Figure 5 is a block diagram of the single mole fraction distribution algorithm shown in Figure 4.

Figures 6a to 6f are comparisons of non-clumping and plotted mole fraction distributions

HRP gas for various oil samples.

Figures 7a to 7f are comparisons of phase envelopes predicted from non-mole fraction distributions

Agglomerated and gas chromatography diagram for different oil samples.

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Figure 8 is a graph of the relative error between the saturated pressure at 250°F

Predicted from non-clumping mole fraction distributions and by a gas chromatogram.

Description:

Figure 1 is a schematic diagram of an illustrative downhole fluid sampling tool 100

5 On drilled cable 102. Downhole fluid sampling tool 100 can be used to obtain

A fluid sample, e.g., a fluid sample of a reservoir fluid taken from an underground formation 104. can yet

This is the analysis of a fluid sample as described here to determine fluid properties that include concentrations

the components. As shown, a wellbore 106 can extend through the subterranean formation 104. While...

Width of the wellbore 106 and generally extends vertically into the underground formation 104, so the principles apply

10 Also described here are boreholes that extend at an angle across the subterranean formation 104, such as a drill

Horizontal and inclined well. For example, although Figure 1 shows a well with a vertical inclination angle

Or low, the method of placing the well and equipment at a high inclination angle can also be used or placed

Horizontally. It should also be realized that while Figure 1 generally depicts a ground operation, owners will realize...

Skill in the field is such that the principles described here are equally applicable to...

15 Subsea operations use floating or offshore drilling platforms or equipment, without moving away from...

Detection field.

As shown, a hoist 108 may be used to lower a downhole sampler 100 into a wellbore 106. The hoist 108 may be positioned on a repair vehicle 110. The hoist 108 may be used, for example, to raise and lower a drilling cable 102 into a wellbore 106. While The jack is displayed

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108 On the repair vehicle 110, it should be recognized that the drilling cable 102 can be alternatively placed from a surface-mounted jack 108 instead of on the repair vehicle 110. The downhole fluid sampling tool 100 may be suspended in the wellbore 106 on a drilling cable 102. Other types of transportation may be used to transport the downhole fluid sampler 100 into the wellbore 106, including

<p dir="rtl">5 Including coiled pipe and wireline drill pipe, for example. The downhole fluid sampling instrument 100 may include an instrument body 114, which may be elongated as shown in Figure 1. The instrument body 114 may be of any suitable material, including, but not limited to, titanium, stainless steel Stainless steel, alloys, plastics, combinations thereof, and the like. Downhole fluid sampling 100 can also include one or</p>

<p dir="rtl">10 More than the sensor 116 to measure the properties of a fluid sample, reservoir fluid, wellbore 106, subterranean formation 104, or the like. The downhole fluid sampler 100 can be used to collect a fluid sample from the subterranean formation 104. The downhole fluid sampler 100 can obtain and store different fluid samples from the subsurface formation 104 individually.</p>

The downhole fluid sampling instrument 100 can also include a modular fluid analysis unit

<p dir="rtl">15 118. The fluid analysis module 118 can derive properties and determine properties</p>

Fluid sample. For example, a typical fluid analysis unit 118 can measure absorption spectra and translate those measurements into the composition of the fluid sample components, which can be the composition of agglomerated components, as described above. The modular fluid analysis unit 118 can also measure the gas-to-oil ratio, live fluid density, live fluid viscosity, formation pressure, and temperature

<p dir="rtl">20 Genesis. The fluid analysis module 118 may include any instrument or combination of instruments that</p>

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May be used to compute, compile, process, send, receive, retrieve, create, transform, store, display, annotate, disclose, record, reproduce, process, or use any information, intelligence, or data for commercial, scientific or scientific purposes. , rule, or occupy another territory. For example,

The fluid analysis module 118 can include a random access memory

<p dir="rtl">5 RAM (memory), one or more processing units such as a central CPU (processing unit) or control logic for computer hardware or software, ROM and/or other types of persistent memory.</p>

Any suitable technology may be used to transmit signals from the downhole fluid sampler 100

to the surface 112. As shown, a communication link 120 may be provided (which may be wired or

<p dir="rtl">10 Wireless, for example) which may send data from a downhole fluid sampler</p>

100 To an information handling system 122 on the surface 112.

The information processing system 122 can include a processing unit 124, a display 126, and an input device

128 (e.g., keyboard, mouse, etc.) and/or computer media 130 (e.g.

(e.g. optical discs, magnetic discs) can store code representing the methods described here.

<p dir="rtl">15 The information processing system 122 is placed on a repair vehicle 110 or is placed on a roof 112.</p>

The information processing system 122 can function as a data acquisition system and possibly a data acquisition system

Data processing analyzes information from the downhole fluid sampling tool 100. e.g

For example, the information processing system 122 can process information to determine fluid properties in

Fluid samples issued from the downhole fluid sampling instrument 100, including identification

<p dir="rtl">20 Turkish azt ingredients, eg. The information processing system 122 can also specify properties</p>

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Additional features of the fluid sample, such as pressure, volume, and temperature properties (e.g., popping point, phase envelope prediction, and so on) based on determining the fluid properties. This processing can occur on the surface 112 in real time. Alternatively, it can occur Treatment at surface 112 or another location after extracting the downhole fluid sampling tool 100 from the wellbore 106.

<p dir="rtl">5 Alternatively, processing may be performed by a wellbore information processing system 106, such as a unit</p>

Typical fluid analysis 118. The fluid properties and resulting fluid properties can then be transmitted to the surface 112, for example, in real time.

Referring now to Figure 2, a schematic diagram of the downhole fluid sampler is shown

100 Placed on a 132 drill string. As shown, it can be extended

10 Borehole 106 through the subsurface formation 104. The downhole fluid sampling instrument 100 may be similar in appearance and operation to the downhole fluid sampling instrument 100 shown.

1, except that Figure 2 shows a downhole fluid sampler 100 placed

On a string of drill pipes 132. You should realize that while Figure 2 generally depicts a drilling system

ground, those skilled in the art will readily recognize that the concepts described here can be applied

15 Equally for seabed drilling operations that use floating or offshore drilling rigs and platforms,

Without moving away from the field of detection.

As shown, a 134 drilling platform can carry a 136 derrick drilling tower

It has a movable mass 138 that raises and removes the drill pipe string 132. It may include a pipe string

Drilling 132 includes, but is not limited to, drill pipe and coiled tubing, as commonly known

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For those skilled in the field. The drill stem 140 kelly can hold the drill pipe string 132 when it is removed via the rotating table 142. A drill bit 144 can be attached to the distal end of the drill pipe string 132 and can be operated either by a downhole motor and/or via a rotary drill bit 144 from the drill pipe string 132. Surface 112. Without limitation, drill bit 144 may include a conical bit

<p dir="rtl">5 Cylindrical bits, PDC bits, natural diamond bits, and any well expanders, reamers, rock core bits, and the like. As the bit 144 rotates, it can create and lengthen a borehole 106 that penetrates various subterranean formations 104. A pump 148 can circulate a drilling fluid through a feed pipe 150 to a drill stem 140, downhole through the inside of a drill pipe string 132 via nozzles in the bit. Drilling 144, and returning it to the surface 112 through the annular space 152 about</p>

<p dir="rtl">10 Drill pipe string 132, and inside a retention pit 154.</p>

The drill bit 144 may be only one piece of a downhole assembly which may include one or more drill collars 146 and a downhole fluid sampling tool 100.

The downhole fluid sampler 100, which can be integrated into drill collars 146), can collect measurements and fluid samples as described herein. As described before,

<p dir="rtl">15 Information from the downhole fluid sampler 100 may be sent to an information processing system 122, which may be located on the surface 112. As shown, a communication link 120 may be provided (which may be wired or wireless, for example) which may transmit Data from the downhole fluid sampler 100 to an information processing system 122 at the surface 112. The information processing system 122 can include a processing unit 124, a display 126, a device</p>

<p dir="rtl">20 input 128 (e.g., keyboard, mouse, etc.) and/or computer media 130 (on</p>

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(e.g., optical disks, magnetic disks) that can store code representing the methods described herein. In addition to or instead of surface treatment 112, downhole treatment may occur (e.g., the typical fluid analysis unit 118 shown in Figure 1). .

Figure 3 shows a flowchart of an illustrative method for determining the properties of a fluid 156. It can be implemented

<p dir="rtl">5 Fluid Properties Method 156 Using the systems shown in Figures 1 and 2, for example, to determine the fluid properties of a fluid sample. The fluid characterization method 156 may be implemented on the surface 112 or in the wellbore 106. For example, a typical fluid analysis unit 118 for a downhole fluid sampling instrument 100 may include a processing unit (e.g., a microprocessor, and so on) which It can operate on one or more implementations</p>

<p dir="rtl">10 Steps of the fluid characterization method 156. As another example, the information processing system 122 may also include a processing unit 124 (e.g., a microprocessor, etc.) which can perform one or more steps of the fluid characterization method 156. Such as To be completed, processing may occur either in the wellbore 106, on surface 112, at a remote location, or at a combination of those locations.</p>

15 In step 158, a fluid sample can be obtained. A fluid sample can be a fluid sample taken

From a reservoir of interest, for example, from the subterranean formation 104 shown in Figures 1 and 2. Any appropriate technique can be used to obtain a fluid sample. As described before, the downhole fluid sampler 100 can be used to collect a fluid sample on a drilling cable 102 (e.g., Figure 1) or on a drill pipe string 132 (e.g., Figure 2),

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For example. For example, a fluid sampler may be operated downhole 100 to obtain a fluid sample. The fluid sample can be obtained at the formation temperature and pressure. It should be understood that the downhole fluid sampling device 100 is an illustrative device only for a demonstration device that can be used to obtain a fluid sample and will be able to be used by those with the skill

<p dir="rtl">5 It is usual in the field to choose an appropriate device and accompanying method to obtain a fluid sample. The fluid sample does not necessarily have to be collected downhole. For example, the techniques described herein can be used to determine fluid sample properties of a product fluid that can be used on surface 112. After obtaining a fluid sample, subsequent processing steps (e.g., steps 160 through 178) can occur on surface 112 or In the wellbore 106. on</p>

<p dir="rtl">10 Alternatively, the fluid sample may be transported to a remote location to perform one or more processing steps</p>

suffix.

In step 160, the fluid sample can be analyzed to derive input variables that determine the properties of the fluid sample. Without limitation, input variables can be obtained from fluid sample measurements. Measurements may be taken in the wellbore 106, on the surface 112, or at a remote location. can use

<p dir="rtl">15 Downhole fluid sampler 100 or other formation evaluation instruments suitable for fluid sample analysis. Any measuring instrument capable of producing a measurable response to a fluid property change may be used. The measuring instrument may contain a detector and/or sensor that detects, for example, density, resistivity/conductivity, viscosity, isoelectricity, radioactivity, dielectric constant, optical density, magnetic resonance, weight, acoustic impedance, acoustic velocity, photoresponse,</p>

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Diffusion coefficients, molecular weight, refractive index at many wavelengths, and combinations

Of which. One or more sensors or detectors may be used in the measuring instrument.

Input variables for a fluid sample that can be derived can include fluid properties that...

It can be obtained from measurements of a fluid sample, including, but not limited to, one or

5 Additional fluid properties that can include more than one concentration of components (e.g., % by weight, and so on), gas-to-oil ratio, live oil density (or dead oil density) and popping point.

One or more can be derived from water fraction by volume, API specific gravity, live oil viscosity, grade

Formation temperature, or formation pressure, among others. As described before, it can be

Turkish ingredients obtained from these measurements are typically the concentration of the ingredient

<p dir="rtl">10 Agglomerated with a concentration of heavier hydrocarbons clumped together. For example, the concentration of ingredients can be provided and the parts of carbon dioxide (CO) shown₂(, methane)CH₄(, ethane)C₂H₆(،</p>

Propane (C₃H₈(, butane)C₄H₁₀(, pentane)C₅H₁₂(And C6+ group. May include

C6+ group is the concentration of all hydrocarbons with six or more carbon atoms agglomerated into a component concentration

One. In some cases, C5 hydrocarbons may not be reported separately, with a group agglomerated

15 C5+ is a hydrocarbon in a single component concentration. In addition, some can also be collected

Minor hydrocarbons, such as C4, C3, or C5 hydrocarbons and mentioned together, for example,

A C3-C4 hydrocarbon group, a C3-C5 hydrocarbon group, and/or a C4-C5 group

Hydrocarbon. These quantities can be stated as percentages by weight or moles. refers to "living oil"

Typically to oil at tank conditions. A sample of a fluid at reservoir conditions may be referred to as...

20 "Living oil." The live oil density of a fluid sample can be obtained from measurements at

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Conditions etc. Store. Without limitation, the live oil density may be obtained using a density sensor, for example, on a downhole fluid sampler 100. The popping point is the temperature and pressure at which the first gas bubble exits the fluid sample. Without limitation, the popping point can be obtained from downhole measurements. In no way

5 Inventory: The gas-to-oil ratio can be obtained by measuring the amount of vapor components

And the liquid components of crude oil using absorption peaks that approach infrared.

The ratio of vapor components to the top oil can be directly related to the gas-to-oil ratio.

In step 162, the initial values of the molecular weight of the C6+ (λ1) components and the density of the C36+ (λ2) components can be obtained. The molecular weight of the C6+ (λ1) components and the density of the C36+ (λ2) components can be

10 (C36+ (λ2) are two unknown values that are determined using the fluid characterization method 156.

Using these values, the concentrations of the fluid sample components, including the concentration of the non-agglomerating component, can be determined. Initial values for the molecular weight of the C6+ components (λ1) and the density of the C36+ components (λ2) can be derived using the input variables obtained in step 160 of the fluid sample analysis.

Then, the mole fraction distribution function can be used to determine the mole fractions of the components of a fluid sample. in

15 In step 164, the mole fraction distribution function can be solved, and in step 166, the mole fractions of the fluid sample components can be determined based on the mole fraction distribution function. The mole fraction distribution function can determine the properties of a reservoir fluid as a function of the mole fraction of different fluid components. Figure 4 displays the distribution

The mole fraction of one carbon atom of live oil for a number of fluid samples. As shown, the molar fraction distribution is provided in Figure 4 for more than ten light oil/gas condensate samples based on

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On the results of gaseous aspiration and distillation in the laboratory. As shown, all samples have a maximum fraction at C1, which may be due to the light nature of the oil, e.g. The mole fraction then decreases dramatically as the number of carbon atoms increases. However, a further increase was observed at C5 until a secondary maximum value could be achieved at C8. After that, the mole fraction decreases towards a plateau-shaped level of zero. The exponentially increasing trend from C5 to C8 and the exponentially decreasing trend from C8 to +C36 can be observed in Figure 5, which is a semi-logarithmic plot given in Figure 4. Based on these observations, the partitioned exponential distribution function can be used as the mole fraction distribution function as the next:

^{- 1( - ) 1} , = 5,…,

^{- 2(- ) 2}, = ,…,200

={

10

15

)1(

In Equation 1, z_i It is the mole fraction of the component with the number of carbon atoms being i and k being a number

One carbon has a maximum local mole fraction, which may vary for different fluid samples.

For the set of samples shown in Figures 4 and 5, k = 8 up to about 13. And σ is,

τ, and α are variables that need to be solved for specific samples, where σ is the scaling variable to adjust

Total mole fraction from C5 to C200, τ and α are variables to adjust the increasing trends

and low (e.g., concavity of curves). The subscripts 1 and 2 in Equation 1 indicate

High and low areas, respectively. The subscript i represents the number of atoms per carbon.

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In step 164, the mole fraction distribution function can be solved. As described before, the mole fraction distribution function can specify the properties of the number of one carbon atom as a function of the mole fraction of a fluid sample. A mole fraction distribution function can include one or more unknown variables that need to be solved to determine the properties of the mole fractions of components in a fluid sample. For example, include

<p dir="rtl">5 Equation 1 Five unknown variables (α1, τ2, τ1, σ, and α2) must be solved before determining the mole fractions of the components. One or more constraints may be used to determine the unknown variables in the mole fraction distribution function. Five constraints may be needed to solve Equation 1, where there are five unknown variables. The basis of the constraints that can be used for the mole fraction distribution function can include, but are not limited to, molar equilibrium, mass equilibrium, the continuous nature of the functions, or combinations thereof</p>

<p dir="rtl">10 Constraints should also include theoretical assumptions, quasi-experimental assumptions, or experimental assumptions. Thus, the identification of unknown variables can be semi-experimental or experimental. Thus, in step 64, the mole fraction distribution function (e.g., Equation 1) can be solved to determine the unknown variables.</p>

In step 166, the mole fraction distribution function can be used to determine the mole fractions of the components. on

<p dir="rtl">15 Without limitation, knowing the unknown variables of the mole fraction distribution function, the mole fraction distribution function can be used to determine the C1-C200 component. For example, the mole fractions of the components determined from the molar distribution function can be the concentration of the non-agglomerating components which includes the molar distribution of the components, including additional parts (C6+, C5, and so on). When using Equation 1, one can Obtain the molar fraction or i(z_i= from 1 to 200) for a sample</p>

<p dir="rtl">20 Fluid.</p>

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In step 168, rapid equation of state calculations can be performed to derive the fluid properties

Calculated. Quick equation-of-state calculations can be performed on the mole fractions of the components specified in step 166. To reduce computational complexity, the mole fractions of the components can be clustered, for example, the mole fractions C35, C34,. . . ,C2,C1, and C36+. Can include

<p dir="rtl">5 Calculated fluid properties determined by rapid calculations of one or more equations of state</p>

From the gas-to-oil ratio or the density of dead oil, for example. “Dead oil” refers to a form

Typical of oil at fairly low pressure that contains largely no dissolved gas

Or a relatively thick oil that has lost its volatile components. Additional calculated fluid properties can include,

But it is not limited to the mole fraction distribution of the liquid, the molar fraction distribution of the vapor, density, and weight

10 Molecular and molar volume of the liquid and vapor fraction of live oil.

Fast calculations can be based on equation of state equations that represent a functional relationship

Between the pressure, volume, and temperature of a fluid sample. Equations of states can be used to predict properties

Physical properties, such as microscopic properties of pressure, volume, and temperature, including the bubbling point, point

Dew, phase envelope, viscosity, density, and combinations thereof.

15 Quick equation of state calculations can use information or properties such as degree

Temperature, pressure, and composition. For example, a simple equation of state is PV=nRT,

Known as the optimum gas law, where P = pressure, V = volume, n = moles, R = optimum gas constant

(also used to convert units), and T = absolute temperature (Kelvin or Arnequin). When

The physical properties and composition of the reservoir fluid Under a known set of conditions, performance can be predicted

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Storage fluid at other pressures and temperatures. Equations of state that can be used can include, for example, expansions of the optimal gas law to take into account individual molecular structures. According to some embodiments, they are third-order equations. Any of the set of state equations can be used. The equation of state can be cubic or non-cubic. That could change

<p dir="rtl">5 Equation of state based on one or more components of the composition of a fluid sample. Equations of state have several names, as they have been modified to improve the match between expected and observed performance. Without limitation, the equation of state may be chosen from one or more of Redlich, Van der Waals, Boyle</p>

Soave-Redlich-Kwong, Peng-Robinson, Peng-Robinson

Schmit-Wenzel, Patek-Teja, Stryjek-Vera, or Esmaeilzadeh-Roshanfekr.

<p dir="rtl">10 In step 170, the calculated fluid properties can be compared to the input fluid variables. As described above, the input fluid variables can be derived from the fluid sample analysis in step 160. For example, the gas-to-oil ratio and live oil density can be measured. From the density of live oil, the density of dead oil can be determined. The calculated fluid properties can include the calculated gas-oil ratio and the calculated dead oil density. Without limitation, it may include comparison</p>

<p dir="rtl">15 Comparing the calculated gas-to-oil ratio to the input gas-to-oil ratio obtained from the fluid analysis in step 160. Without limitation, the comparison may also include comparing the calculated gas-to-oil ratio and the dead oil density derived from the input obtained from the analysis Fluid in step 160.</p>

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The potential tolerance error, step 172, can be used to determine whether another iteration is needed via the mole fraction distribution function (steps 162 to 170) and quick equation of state calculations (step 168). The potential tolerance error can be a small value chosen to influence It affects the number of iterations and the total computation time, but it may have minimal impact on the final results

<p dir="rtl">5 As a limitation, if the relative differences between the input fluid variables and the calculated fluid variables do not fall within the potential tolerance error, another iteration may be needed. For example, if the relative difference between the calculated gas-oil ratio and the input gas-oil ratio and between the calculated waste oil density and the waste oil density derived from the input waste oil density does not fall within the potential tolerance error, another iteration may be needed. If a possible tolerance error is identified, it is possible</p>

<p dir="rtl">10 If another iteration is needed, the values for the molecular weight of the components (C₆₊ (λ1) and the density of the components (C36+ (λ2) (Step 174) and steps can be repeated from 164 to 172. Updating the values for the molecular weight of the components (C) can be used₆₊ (λ1 and density of components (C₃₆₊ (λ2) Any of a variety of different analysis algorithms, including but not limited to the Newton-Raphson method. The process of steps 164 to 172 can be repeated with the possibility</p>

<p dir="rtl">15 Obtain values for the molecular weight of the C6+ (λ1) components and the density of the C36+ (λ2) components up to the comparison values given in step 170 or within the possible tolerance error given in step 172.</p>

When the potential tolerance error in step 172 is met, the fluid characterization method 156 proceeds to step 176 with the result that improved molecular weight values for the components are obtained

<p dir="rtl">20 The C6+ (λ1) and C36+ (λ2) components density of the fluid sample. In frame 178, the values can</p>

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Optimized to use optimized values to produce output mole fractions of components (e.g.

molar distributions (C1-C200) and pressure, volume, and temperature properties, such as popping point and prediction

Phase envelope, among other things. Without limitation, optimized values may be used

Calculates output values for mole fractions of components (for example, C1 molar distributions

5 C200) and the properties of pressure, volume, and temperature. The mole fractions of the components can be:

Find out the mole fractions of non-agglomerating components. Non-agglomerating mole fractions can include mole fractions

The molarity of components per carbon atom ranges from C1 to C200. Alternatively, the mole fractions of non-agglomerating components may be expanded, but they may still contain some hydrocarbons

The heaviest lump in a group. For example, ten, twenty, triple or more can be provided

<p dir="rtl">10 The molar fractions of the components for C5+ hydrocarbons.</p>

The disclosed techniques for fluid characterization operations, such as the fluid characterization method 156, can be performed in real time. “Real-time” performance refers to characterization

“quick” fluid sampling performed while using downhole fluid sampling tool 100 (or other tool) in the field, compared to use in the field or after use in the field, e.g., performance in

15 Real time, for example while recording drilling performance, without recovering the fluid sampling tool

Downhole 100 or a fluid sample from the bottom of the well. It can allow performing the process of determining fluid properties

In real time, the user determines the molar fractions of components and predicts the phase envelope at the same time

Take measurements at or around this time.

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Without limitation, the above techniques can be used in a variety of methods and systems to determine

Properties of a fluid sample. An example given could include how to determine fluid properties

To obtain a fluid sample of a reservoir fluid; Analysis of the fluid sample to derive the input variables, where

The input variables include fluid properties obtained from measuring the fluid sample; to set

5 Mole fractions of the components of a fluid sample using the mole fraction distribution function; Determine the properties of the fluid

Calculated using quick calculation of the equation of state. An example given could include a system

To determine the characteristics of a fluid sample on a downhole fluid sampling tool that works to obtain

on fluid samples while being placed in a wellbore; A processing unit analyzes the fluid sample

To derive the input variables, where the input variables include the obtained fluid properties

10 In order to measure a fluid sample, it determines the mole fractions of the components of the fluid sample using a distribution function.

Molar fractions, and determining the fluid properties calculated using the quick calculation of the equation of state.

Fluid characterization methods and/or systems for determining the properties of a fluid sample can include any of...

The numerous features of the compositions, methods, and systems disclosed herein. Without limitation, the methods and/or systems may also include operating a downhole fluid sampling instrument in

15 Borehole to obtain a fluid sample. Methods and/or systems may also include the condition that

The fluid properties of the input variables include the concentration of components, the density of the live oil, and the gas-to-oil ratio. Methods and/or systems may also include a situation in which there is concentration

Components is the concentration of agglomerated components. Methods and/or systems may also include obtaining

On the initial values of the molecular weight of the C6+ components and the density of the C36+ components of the fluid sample.

20 Methods and/or systems may also include the case in which initial values are used in

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Mole fraction distribution function to determine the mole fractions of components. The methods and/or systems may further include the case where the molar fractions of components determined using a mole distribution function are the molar fractions of non-agglomerated components at an agglomerated component concentration obtained in the fluid sample analysis step. Methods and/or systems may also include the condition in which

<p dir="rtl">5 The mole distribution function is expressed in equation (1). The methods and/or systems may also include the case in which the step of determining the mole fractions of the components of a fluid sample includes solving the mole distribution function for one or more unknown variables. The methods and/or systems can further include determining the mole fractions of the components of the fluid sample based on the mole distribution function</p>

<p dir="rtl">10 Methods and/or systems also compare calculated fluid properties with input variables, including:</p>

Calculated fluid properties and variables introduced into the gas-to-oil ratio and dead oil density. The methods and/or systems may also include determining updated values for the molecular weight of the C6+ components and the density of the C36+ components of the fluid sample if the difference in the calculated fluid properties does not fall within a tolerance error, then repeating the steps for determining the molar fractions of the components and determining

<p dir="rtl">15 Calculated fluid properties. Methods and/or systems may also include the state in which they are involved</p>

Downhole fluid sampling tool on an elongated tool body and sensor. The methods and/or systems may further include the case where the processing unit is distributed between a downhole processing unit and a processing unit located at the surface.

Examples

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To facilitate a better understanding of the present technology, the following examples of some specific embodiments are shown. no

The following examples should in no way be considered limiting or limiting the scope of the invention.

The techniques disclosed herein were used to characterize six different oil samples. Included

Oil samples at different gas-to-oil ratios ranging from 100 to 2000 cm.

<p dir="rtl">5 cubic/cubic centimeter. The expected molar fractions of the components were compared from the characterization method</p>

Fluid 156 with gas chromatography data measured in the laboratory. First, the full-length fluid compositions from the gas ichthyogram report were compiled into components C4-5, C3, C2, C1, CO2, and C6+, in weight percentages to simulate downhole instrument measurement results. This data can be referred to as mock instrument data. . The false instrument data can then be used with the gas to gas ratio

<p dir="rtl">10 The oil and dead oil density are in the input fluid properties derived in step 160 of Figure 3. Depending on the gas-to-oil ratio and dead oil density, clumping can be removed from the instrument data.</p>

And determine its characteristics in steps 162 to 170, then repeat it until the error tolerance is met.

Likely. The molar fractions of the non-agglomerated components of six oil samples were compared with plot data

Inhale the gas in Figures 6a to 6f. The carbon atom number 36 refers to the 36+ fraction. as

15 It is clear from Figures 6a to 6f that the mole fractions of the components and the chromatogram data agreed

Gas well. Furthermore, mole fractions of non-agglomerating components can be used

And gas chromatography data to produce the phase envelope. Figures 7a to 7f show a comparison

Phase envelope predictions derived from mole fractions of non-agglomerated components and plot data

Get gas. As can be seen in Figures 7a to 7f, the phase envelope predictions are consistent

<p dir="rtl">20 It works well for mole fractions of non-agglomerated components and gas chromatography data. when</p>

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Under storage conditions, the popping point may be taken into account. Thus, Figures 8a through 8f show a comparison of the relative error between the saturation pressure at 250°F and the expected molar fractions of the non-agglomerated components and the gas chromatogram data. It has been observed that the relative error increases when the ratio of gas to oil in the fluid increases. The maximum error was about 5%.

<p dir="rtl">5 The foregoing description provides several embodiments of systems and methods of use that may contain different method steps and alternative combinations of components. You should understand that although individual embodiments may be discussed here, the present disclosure covers all combinations of the disclosed embodiments, including, but not limited to, combinations of various components, combinations of method steps, and system features.</p>

<p dir="rtl">10 You should understand that when compositions and methods are described in terms of “comprising,” “containing,” or “involving” a plurality of components or steps, the compositions and methods may also “consist primarily” or “comprising” a plurality of components or steps. Ingredients and steps. Furthermore, indefinite articles, as used in protective elements, are defined here as meaning one or more of the elements they refer to.</p>

<p dir="rtl">15 Thus, the present embodiments are well configured to achieve the stated objectives and features as well as those inherent therein. The specific embodiments disclosed above are illustrative only, and the present invention may be modified and implemented in various but equally obvious ways to those skilled in the art upon making use of the information contained herein. Although individual embodiments are discussed, all combinations of those embodiments are covered in their entirety. Moreover, there are no restrictions imposed on the details</p>

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Construction or design mentioned herein, other than what is described in the protections below.

Likewise, the terms contained in the elements of protection have their plain and clear meaning unless the opposite is clearly and publicly specified by the patentee. Therefore, it is clear that specific illustrative embodiments disclosed may be changed or modified and all such variations shall be considered within the scope and substance of

<p dir="rtl">5 The present invention. If there is any conflict in uses of a word or term in this specification and one or more patents or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification shall be used.</p>

Reference acclaim for graphics

Figure 3

<p dir="rtl">10 158 Obtaining a fluid sample</p>

160 Analysis of a fluid sample to derive the input fluid variables for the fluid sample

162 Obtain an initial value for λ1 and 2d

164 Solve the molar fraction distribution function

<p dir="rtl">166 Based on the mole fraction distribution function, determine the mole fractions of the components</p>

15 168 Perform quick equation of state calculations to derive the calculated properties

170 Comparing the calculated fluid properties with the input fluid variables

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172 Is there a potential discrepancy?

174 Get updated values for 22,21

Yes

B No

176 Obtaining improved values for No. 8 and 22

178 Produce output for 0200-01 molar distribution, fluid sample phase properties, and/or envelope

Phase the fluid sample

Figure 4

<h3 dir="rtl">10 A mole fraction</h3>

b Number of carbon atoms

Figure 5

A mole fraction

15 b Number of carbon atoms

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10

Figure 6a

A mole fraction

b The number of carbon atoms

C Sample 1

D Composition - GC

E. Composition - Eliminate agglomeration

Figure 6b

A mole fraction

b The number of carbon atoms

C Sample 2

D Composition - GC

E. Composition - Eliminate agglomeration

15

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Figure 6c

A mole fraction

b The number of carbon atoms

C Sample 3

5 D Composition - GC

E. Composition - Eliminate agglomeration

Figure 6d

A mole fraction

10 b The number of carbon atoms

C Sample 4

D Composition - GC

E. Composition - Eliminate agglomeration

15 Figure 6e

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<tr><td><p dir="rtl">Molly fraction</p><p dir="rtl">The number of carbon atoms</p></td><td><p dir="rtl">a</p><p dir="rtl">B</p></td></tr><tr><td><p dir="rtl">Sample 5</p></td><td><p dir="rtl">^C</p></td></tr><tr><td><p dir="rtl">Composition - GC</p></td><td><p dir="rtl">Dr</p></td></tr><tr><td><p dir="rtl">Formula - decaking</p></td><td><p dir="rtl">5 e</p></td></tr><tr><td colspan="2"><p dir="rtl">Figure 6f</p></td></tr><tr><td><p dir="rtl">Molly fraction</p></td><td><p dir="rtl">a</p></td></tr><tr><td><p dir="rtl">The number of carbon atoms</p></td><td><p dir="rtl">B</p></td></tr><tr><td><p dir="rtl">Sample 6</p></td><td><p dir="rtl">10 C</p></td></tr><tr><td><p dir="rtl">Composition - GC</p></td><td><p dir="rtl">Dr</p></td></tr><tr><td><p dir="rtl">Formula - decaking</p></td><td><p dir="rtl">e</p></td></tr><tr><td colspan="2"><p dir="rtl">Figure 7a</p></td></tr><tr><td><p dir="rtl">Temperature (F)</p></td><td><p dir="rtl">15 a</p></td></tr>

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b Pressure (psi)

C Sample 1

D Phase envelope - E deagglomeration

E Critical points - removing agglomeration

5 And the phase envelope - GC

g Critical Points - GC

Figure 7b

A Temperature (F)

10 b Pressure (psi)

C Sample 2

D Phase envelope - E deagglomeration

E Critical points - removing agglomeration

And the phase envelope - GC

15 g Critical Points - GC

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Figure 7c

A Temperature (F)

b Pressure (psi)

5 C Sample 3

D Phase envelope - E deagglomeration

E Critical points - removing agglomeration

And the phase envelope - GC

g Critical Points - GC

10

Figure 7d

A Temperature (F)

b Pressure (psi)

C Sample 4

15 D Phase envelope - E deagglomeration

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E Critical points - removing agglomeration

And the phase envelope - GC

g Critical Points - GC

5 Figure 7e

A Temperature (F)

b Pressure (psi)

C Sample 5

D Phase envelope - E deagglomeration

10 E Critical points - removing agglomeration

And the phase envelope - GC

g Critical Points - GC

Figure 7f

15 A Temperature (F)

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b Pressure (psi)

C Sample 6

D Phase envelope - E deagglomeration

E Critical points - removing agglomeration

<p dir="rtl">5 And the phase envelope - GC</p>

g Critical Points - GC

Figure 8

A sample index

10 B GOR)cm³/poison³(

C Absolute relative error in saturated pressure (%)

GOR D

e Relative error of saturated pressure

And 5% of error

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