Fluid compressibility factor and method of determination

Abstract

Methods for determining a compressibility factor are disclosed. A method may include disposing a downhole fluid analysis tool within a wellbore, extracting a formation fluid from the wellbore, pumping the formation fluid through the downhole fluid analysis tool, measuring at least one of a flowline temperature, a flowline pressure, a formation fluid mass density, and a pumped volume, measuring compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) in the formation fluid, estimating pluralities of molecular weight of C6+ in the formation fluid, estimating pluralities of molecular weight of the formation fluid, calculating the compressibility factor of the formation fluid based upon the flowline temperature, the flowline pressure, the formation fluid mass density, and the molecular weight of the formation fluid, and outputting the compressibility factor of the formation fluid.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to U.S. Provisional Patent Application No. 63 / 479,383 that was filed on Jan. 11, 2023, which is herein incorporated by reference in its entirety.FIELD OF THE DISCLOSURE

[0002] Aspects of the disclosure relate to fluid compressibility factors. More specifically, aspects of the disclosure relate to calculation of fluid compressibility factors in real time.BACKGROUND

[0003] Fluid compressibility factor (or Z factor or gas deviation factor) is of great importance for gas and gas condensate production and transportation. In pressure-volume-temperature (PVT) laboratory reports, Z factors are reported for gas and gas condensate whereas isothermal compressibility coefficients are reported only in black oil PVT reports. There is a need to determine Z factors for gas and gas condensate downhole in real time. There is also a need to provide values for a Z factor to correct downhole pump-out volume and flowrate so that more accurate interval pressure transient tests (IPTT) may be obtained for gas and gas condensate reservoirs.

[0004] There is a need to provide a method that simplifies comparted conventional apparatuses and methods.

[0005] There is a further need to provide real time estimates of Z factors for use in field operations of hydrocarbon recovery.

[0006] There is a still further need to reduce economic costs associated with operations and apparatus described above with conventional tools.SUMMARY

[0007] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized below, may be had by reference to embodiments, some of which are illustrated in the drawings. It is to be noted that the drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments without specific recitation. Accordingly, the following summary provides just a few aspects of the description and should not be used to limit the described embodiments to a single concept.

[0008] In one example embodiment, a method for determining a compressibility factor is described. The method may comprise disposing a downhole fluid analysis tool within a wellbore. The method may also comprise extracting a formation fluid from the wellbore and pumping the formation fluid through the downhole fluid analysis tool. The method may also comprise measuring at least one of a flowline temperature, a flowline pressure, a formation fluid mass density, and a pumped volume. The method may also comprise measuring compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) in the formation fluid. The method may also comprise estimating pluralities of molecular weight of C6+ in the formation fluid. The method may also comprise estimating pluralities of molecular weight of the formation fluid. The method may also comprise calculating the compressibility factor of the formation fluid based upon the flowline temperature, the flowline pressure, the formation fluid mass density, and the molecular weight of the formation fluid. The method may also comprise outputting the compressibility factor of the formation fluid.

[0009] In another example embodiment, a method is disclosed. The method may comprise disposing a downhole fluid analysis tool within a wellbore, extracting a formation fluid from the wellbore, and pumping the formation fluid through the downhole fluid analysis tool and to a sample container. The method may further comprise obtaining weight percent compositions of CO2, C1, C2, C3, C4, C5 and C6+ in the formation fluid. The method may further comprise estimating a molecular weight of the C6+ in the formation fluid. The method may further comprise estimating a molecular weight of the formation fluid. The method may further comprise performing pressure-density measurements on the formation fluid using one of depressurization in the downhole fluid analysis tool or pressurization at the sample container. The method may further comprise obtaining pluralities of temperature, pressure, and formation fluid mass density. The method may further comprise calculating pluralities of compressibility factor of the formation fluid. The method may further comprise outputting the calculated compressibility factor of the formation fluid.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

[0011] FIG. 1 is a list of component molecular weights.

[0012] FIG. 2 is a plot of sensor pressure data, SOI data and resistivity cell temperature.

[0013] FIG. 3 is an expanded view of the data of FIG. 2 for plots of pressure vs. time, temperature vs. time and density vs. time.

[0014] FIG. 4 shows the cross-plot of ramping-up data of density and temperature versus pressure for the sampling case

[0015] FIG. 5 is a illustrates the gas oil ratio (GOR), composition, green fraction and SOI pressure variations with time.

[0016] FIG. 6 is a plot of Z factor as a function of pressure in accordance with one example equation of the disclosure.

[0017] FIG. 7 is a plot of density as a function of pressure for Case 2.

[0018] FIG. 8 is a plot of Z factor as a function of pressure for Case 2.

[0019] FIG. 9 is a plot of variations of temperature, compositions, pressure and density during sample cleanup for gas condensate with a specified GOR.

[0020] FIG. 10 is a plot of estimated fluid molecular weight for gas condensate with a specified GOR.

[0021] FIG. 11 is a plot of estimated Z factor using one example embodiment of the disclosure.

[0022] FIG. 12 is a comparison of estimated fluid Z factor laboratory Z factor for gas condensate with GOR of ~5900 scf / bbl.

[0023] FIG. 13 is an example method of calculating a Z factor in one example embodiment of the disclosure.

[0024] FIG. 14 is a second example method of calculating a Z factor in one example embodiment of the disclosure.

[0025] To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures (“FIGS”). It is contemplated that elements disclosed in one embodiment may be beneficially utilized on other embodiments without specific recitation.DETAILED DESCRIPTION

[0026] In the following, reference is made to embodiments of the disclosure. It should be understood, however, that the disclosure is not limited to specific described embodiments. Instead, any combination of the following features and elements, whether related to different embodiments or not, is contemplated to implement and practice the disclosure. Furthermore, although embodiments of the disclosure may achieve advantages over other possible solutions and / or over the prior art, whether or not a particular advantage is achieved by a given embodiment is not limiting of the disclosure. Thus, the following aspects, features, embodiments and advantages are merely illustrative and are not considered elements or limitations of the claims except where explicitly recited in a claim. Likewise, reference to “the disclosure” shall not be construed as a generalization of inventive subject matter disclosed herein and should not be considered to be an element or limitation of the claims except where explicitly recited in a claim.

[0027] Although the terms first, second, third, etc., may be used herein to describe various elements, components, regions, layers and / or sections, these elements, components, regions, layers and / or sections should not be limited by these terms. These terms may be only used to distinguish one element, components, region, layer or section from another region, layer or section. Terms such as “first”, “second” and other numerical terms, when used herein, do not imply a sequence or order unless clearly indicated by the context. Thus, a first element, component, region, layer or section discussed herein could be termed a second element, component, region, layer or section without departing from the teachings of the example embodiments.

[0028] When an element or layer is referred to as being “on,”“engaged to,”“connected to,” or “coupled to” another element or layer, it may be directly on, engaged, connected, coupled to the other element or layer, or interleaving elements or layers may be present. In contrast, when an element is referred to as being “directly on,”“directly engaged to,”“directly connected to,” or “directly coupled to” another element or layer, there may be no interleaving elements or layers present. Other words used to describe the relationship between elements should be interpreted in a like fashion. As used herein, the term “and / or” includes any and all combinations of one or more of the associated listed terms.

[0029] Some embodiments will now be described with reference to the figures. Like elements in the various figures will be referenced with like numbers for consistency. In the following description, numerous details are set forth to provide an understanding of various embodiments and / or features. It will be understood, however, by those skilled in the art, that some embodiments may be practiced without many of these details, and that numerous variations or modifications from the described embodiments are possible. As used herein, the terms “above” and “below”, “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, and other like terms indicating relative positions above or below a given point are used in this description to more clearly describe certain embodiments.

[0030] The Z-factor (the fluid compressibility factor) is used for various engineering purposes, which include estimation of gas reserves, prediction of future production, design of oil and gas separators, design of pipelines for the transmission of produced gas, correction of volumetric flowrate pumped in flowlines, among others. The fluid compressibility factor (Z) is a measure of its deviation from ideal gas behavior. The Z-factor of fluid can be obtained with the trapped fluid in a closed system during the isothermal depressurization (or pressurization) while maintaining the single phase above its saturation pressure. It is defined in terms of the pressure-volume-temperature (or PVT) data as followsZ=PVnRT=PvRT,(1)where Z, n, V, v, P, and T are the Z (compressibility) factor, mole, volume, molar volume, pressure, and temperature of the tested fluid, respectively. R is the universal gas constant. In order to obtain accurate fluid Z (compressibility) factor estimates, one would need accurate pressure-volume-temperature data in order to perform the calculation prescribed in Eq. (1). However, obtaining accurate pressure versus fluid volume data is an intricate issue because the volume expansion under pressure is not only accounted for by the expansion of the fluid itself, but also by the finite compliance of the material comprising the flowline loop as well as the expansion of many elastomer seals along the flowline. These extra volume expansions due to the finite compliance of material and elastomer expansion are likely pressure dependent and typically not taken into account in the computation. This often leads to serious errors in estimating the fluid Z (compressibility) factor using the PVT data.On the other hand, fluid compressibility is defined ascg=1ρ⁢(∂ρ∂P)T=-1V⁢(∂V∂P)T=1P-1Z⁢(∂Z∂P)T,(2)Thus, we have at isothermal conditions(∂ln⁢ Z∂P)T=1P+cg,(3)ln⁢Z2Z1=∫P1P2(1P+cg)⁢dP=ln⁢P2P1+∫P1P2cg⁢dP,(4)To alleviate the problems of deriving the fluid Z factor from PVT data, an alternative approach is disclosed herein, in one non-limiting embodiment, based on the density measurements obtained by a density sensor such as the DV-rod sensor in a closed system, where the fluid Z (compressibility) factor can be related to the fluid mass density by:Z=PVnRT=MPρ⁢RT,(5)where M and ρ are the molecular weight (molar mass) and density of the fluid, respectively. The fluid density is a function of pressure and temperature while the molecular weight is independent of pressure and temperature if pressure at specified temperature is above saturation (bubble / dew) point pressure. Eq. (5) is the basis of deriving the Z factor from fluid composition, density, pressure, and temperature measurements. In practicality, some downhole tools have all these measurements including pressure (P), temperature (T), mass density (ρ), compositions, etc., during sample cleanup in real time. The only unknown in Eq. (5) is the molecular weight of fluid. Furthermore, Downhole Fluid Analysis (heinafter “DFA”) composition measurements can be used to estimate molecular weight of the fluid as follows.According to DFA compositions in weight fraction, fluid average molecular weight can be computed by the following equation:M=∑yi⁢Mi=1∑wiMi,(6)where yi, wi and Mi are the mole fraction, weight fraction and molecular weight of component i. The molecular weight of component i is given in Table 1, provided at FIG. 1.In embodiments, the molecular weight of C6+ is estimated by the following correlation, which is developed from a large PVT laboratory database consisting of over 2500 different samples of reservoir fluids from heavy oil, black oil, volatile oil, rich-gas condensate, lean-gas condensate, wet gas to dry gas:MC⁢6+=1⁢0⁢7.7⁢5⁢5(1-0.8⁢399⁢ wC⁢6+),(7)Where wC6+ is the weight fraction of C6+ measured by DFA. The other correlations can also be used for estimating molecular weight of C6+. For gas and gas condensate, weight fraction of C6+ is not dominant unlike black oil because weight fraction of C6+ is much smaller than that of black oil. Therefore, Eq. (7) may not cause a big error for the average molecular weight of gas and gas condensate. As will be understood by people skilled in the art, molecular weight of C6+ is what hinders conventional researchers from estimating various PVT properties downhole. In one example embodiment, disclosed above, equation (7) may provide the necessary correlation, missing from conventional analysis. In another example embodiment, a machine learning algorithm, as discussed in U.S. Pat. No. 10,781,686 may be used. In another example embodiment, the molecular weight (MW) of the plus fraction may be obtained from an equation of state bulk tuning. In this embodiment, downhole fluid composition, such as CO2, C1 to C5, C6+ and measurements of some of the properties, such as density, saturation pressure and gas oil ration, viscosity and compressibility may be obtained and used. The molecular weight of the plus fraction may be directly tuned against the measured properties. In another example embodiment, if the flowline decompression is applied to uncontaminated fluid, the molecular weight of the plus fraction may be known from the field.The new method can be used for any data points during sample cleanup by combining Eqs. (5)-(7). It should be noted that compositions are changing with OBM (oil based mud) filtrate contamination, thus the Z factor also changes during cleanup.In addition, this method can be used by apparatuses to obtain a Z factor (compressibility) of a fluid using density and composition data described above because a downhole PVT tool has a closed system in which the fluid can be pressurized or depressurized. In this case, Z factor changes may be obtained with pressure for a fluid with fixed compositions.On the other hand, in the sampling mode, after a sample bottle is filled up, the fluid in the sample bottle is continuously pressurized until the pump is stopped. Since it is a closed system, the pressure in the flowline will continuously ramp up as pumping continues. Therefore, the sensor measurements such as composition, density, temperature, and pressure along the flowline can be used to derive the fluid Z factor.In another embodiment, the DFA compositions can be delumped and characterized by the method described in U.S. Pat. No. 7,920,970. Then an Equation of State (EoS) can be used to calculate fluid density and Z factor.

[0040] Three example cases will be discussed herein:Case 1

[0041] Here a sampling project is used for demonstration. Located downstream from a pump are a spectrometer, a density / viscosity sensor, and a temperature / pressure sensor. FIG. 2 shows the pressure data (top subplot), the temperature / pressure sensor and resistivity cell temperature data (middle subplot), and the density / viscosity sensor density data (bottom subplot) for the entire duration of this sampling station. The sample bottle is filled at about 9300-9430 sec. After filling up, pumping will lead to the ramp-up of flowline pressure as indicated in the pressure data in the bottom subplot of FIG. 3. FIG. 2, therefore, is a graph of sensor data for the temperature / pressure sensor pressure data (top subplot), the density / viscosity sensor and resistivity cell temperature data (middle subplot), and the density / viscosity sensor density data (bottom subplot) acquired in this sampling station.

[0042] For clarity, FIG. 3 zooms in the blown-up plots of pressure-vs-time (top), temperature-vs-time (middle) and density-vs-time for the case. As indicated in the plot, the pressure in the flowline remains flat while filling up the sample bottle. As soon as the bottle is filled up, continuous pumping causes the ramping-up of pressure (i.e. over-pressurized) as well as the density. As a result, FIG. 3 provides blown-up plots of pressure-vs-time (top), temperature-vs-time (middle) and density-vs-time for the sample collection case.

[0043] FIG. 4 shows the cross-plot of ramping-up data of density and temperature versus pressure for the sampling case. The squares on the plots indicate the data points whereas the lines are the best-fit trend lines. In this example, the actual change in temperature is very small (from 247.30 to 247.55° F.). The thick line and thick squares of data indicate the data points whereas the lines are the best-fit trend lines.

[0044] FIG. 5 illustrates the GOR, composition, green fraction and temperature / pressure sensor pressure variations with time. In this example, the DFA GOR for the gas condensate is 95,000 scf / bbl.

[0045] The compositions from in-situ fluid analysis for case 1 are given in Table 2.TABLE 2Fluid compositions.Componentsweight fractionCO20.1300C10.7020C20.0632C3-50.0074C6+0.0974

[0046] The molecular weight of C6+ estimated by Eq. (7) is 117.35 g / mol for this example. The delumped compositions and molecular weight are listed in Table 3 for case 1.TABLE 3The delumped compositions and molecular weightMolecularWeightweightwi / MiComponentsfractiong / molmolCO20.1300044.012.954E−03C10.7020016.044.376E−02C20.0632030.072.102E−03C30.0030844.106.992E−05C40.0024758.124.244E−05C50.0018572.152.564E−05C6+0.09740117.358.300E−04SUM1.000004.978E−02M, g / mol20.09

[0047] In this example, the average molecular weight calculated according to in-situ fluid analysis data is 20.09 g / mol whereas the PVT laboratory average molecular weight is 20 g / mol. The estimation is in excellent agreement with the laboratory data for case 1.

[0048] According to the information given above for case 1, the Z factor calculated by Eq. (5) is shown in FIG. 6. In this example, the EoS calculated Z factor is also compared in FIG. 6. For case 1, the results from Eq. (5) and EoS are in good agreement. In this example, we use a linear relation to represent Z factor as a function of pressure. Other functions can also be utilized, such as logarithm or exponential functions, or the Tait equation.Case 2

[0049] The 2nd example is a gas condensate with GOR of 13,000 scf / bbl. For case 2, the density vs. pressure is shown in FIG. 7. FIG. 7 also depicts the EoS predictions which are in good agreement with density / viscosity sensor measurements.

[0050] Table 4 gives the delumped compositions and molecular weight of Case 2. For this example, the molecular weight of C6+ estimated by Eq. (6) is 149.77 g / mol and the average fluid molecular weight is 28.85 g / mol and laboratory is 28.67 g / mol. Thus, good agreement is obtained for case 2.TABLE 4Delumped compositions and molecular weight for case 2Componentwt %Mi, g / molwt % / MiCO21.244.010.0273C143.2916.042.6984C26.5730.070.2185C37.3844.100.1674C45.2258.120.0898C52.9472.150.0407C6+33.4149.770.2230Sum1003.4657M, g / mol28.85

[0051] For case 2, the Z factor as a function of pressure is shown in FIG. 8. The solid line is the Z factor calculated by Eq. (5), triangles are the Z factors that are calculated by EoS and squares are Z factors that are calculated by laboratory data. All of the measured Z factors are in good agreement.Case 3

[0052] This example shows a rich gas condensate with GOR of 5900 scf / bbl. For case 3, as shown in FIG. 9, the continuous compositions, pressure, temperature, and density vary with pumped fluid volume during sample cleanup.

[0053] For case 3, fluid molecular weight estimated using Eq. (6) is given FIG. 10. The laboratory measured molecular weight is 34.38 g / mol for this example. The new method value is 34.32 g / mol for this example. Thus, there is good agreement in case 3.

[0054] FIG. 11 shows the Z factor estimated using Eq. (5) for case 3.

[0055] FIG. 12 compares the Z factor estimated using Eq. (5) with laboratory values for case 3. As shown, there is good agreement.

[0056] In one example embodiment shown in FIG. 13, a method 1300 may be used to calculate values, as described above. In this embodiment, the method 1300 may begin by disposing a downhole fluid analysis tool within a wellbore. Further, the method 1300 may include extracting a formation fluid from the wellbore, pumping the formation fluid through the downhole fluid analysis tool, and performing a sample cleanup. Further in this embodiment, the following method steps may be performed:

[0057] 1. Measure pluralities of flowline temperature (Ti), flowline pressure (Pi), fluid mass density (ρi) and pumped volume (Vi) at time ti during the sample cleanup at 1302.

[0058] 2. Measure pluralities of DFA measured compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) at time ti during sample cleanup at 1304.

[0059] 3. Estimate pluralities of molecular weight of C6+ (MC6+) using Eq. (7) or other correlations (or machine learning methods) at 1306.

[0060] 4. Estimate pluralities of molecular weight of the pumped reservoir fluid (Mi) using Eq. (6) at 1308.

[0061] 5. Calculate pluralities of Z factor (Zi), the compressibility factor, using Eq. (5) based on Ti, Pi, ρi, and Mi at 1310.

[0062] 6. Output the calculated Z factor, the calculated compressibility factor, at pumped volume (Vi) or at time ti during sample cleanup at 1312.

[0063] In another example embodiment shown in FIG. 14, a second method 1400 may be performed. In this embodiment, the method 1400 may begin by disposing a downhole fluid analysis tool within a wellbore. Further, the method 1400 may include extracting a formation fluid from the wellbore and pumping the formation fluid through the downhole fluid analysis tool and to a sample container. Additionally, this method may include steps, as indicated below:

[0064] 1. Measure DFA measured compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) at time ti at 1402.

[0065] 2. Estimate a molecular weight of C6+ (MC6+) using Eq. (7) or other correlations (or machine learning methods) at 1404.

[0066] 3. Estimate a molecular weight of the pumped reservoir fluid (Mi) using Eq. (6) at 1406.

[0067] 4. Perform pressure-density measurements using either depressurization in the downhole fluid analysis tool or pressurization prior to closing a sample container valve on the sample container at 1408.

[0068] 5. measure pluralities of temperature (Ti), pressure (Pi), and formation fluid mass density (ρi) at 1410.

[0069] 6. Calculate pluralities of Z factor (Zi), the compressibility factor, using Eq. (5) based on Ti, Pi, ρi, and M at 1412.

[0070] 7. Output the calculated Z factor, the calculated compressibility factor, during the depressurization or pressurization at 1414.

[0071] In one example embodiment, a method for determining a compressibility factor is described. The method may comprise disposing a downhole fluid analysis tool within a wellbore. The method may also comprise extracting a formation fluid from the wellbore and pumping the formation fluid through the downhole fluid analysis tool. The method may also comprise measuring at least one of a flowline temperature, a flowline pressure, a formation fluid mass density, and a pumped volume. The method may also comprise measuring compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) in the formation fluid. The method may also comprise estimating pluralities of molecular weight of C6+ in the formation fluid. The method may also comprise estimating pluralities of molecular weight of the formation fluid. The method may also comprise calculating the compressibility factor of the formation fluid based upon the flowline temperature, the flowline pressure, the formation fluid mass density, and the molecular weight of the formation fluid. The method may also comprise outputting the compressibility factor of the formation fluid.

[0072] In another example embodiment, the method may be performed wherein the molecular weight of C6+ in the formation fluid is calculated using a formula of:MC⁢6+=1⁢0⁢7.7⁢5⁢5(1-0.8⁢399⁢ wC⁢6+).

[0073] In another example embodiment, the method may be performed wherein the molecular weight of C6+ in the formation fluid is calculated using machine learning methods.

[0074] In another example embodiment, the method may be performed wherein the compressibility factor is calculated using a formula of:Z=PVnRT=MPρ⁢RT.

[0075] In another example embodiment, the method may be performed wherein the outputting of the compressibility factor is at a time during sample cleanup.

[0076] In another example embodiment, the method may be performed wherein the compositions are determined during sample cleanup activities.

[0077] In another example embodiment, a method is disclosed. The method may comprise disposing a downhole fluid analysis tool within a wellbore, extracting a formation fluid from the wellbore, and pumping the formation fluid through the downhole fluid analysis tool and to a sample container. The method may further comprise obtaining weight percent compositions of CO2, C1, C2, C3, C4, C5 and C6+ in the formation fluid. The method may further comprise estimating a molecular weight of the C6+ in the formation fluid. The method may further comprise estimating a molecular weight of the formation fluid. The method may further comprise performing pressure-density measurements on the formation fluid using one of depressurization in the downhole fluid analysis tool or pressurization at the sample container. The method may further comprise obtaining pluralities of temperature, pressure, and formation fluid mass density. The method may further comprise calculating pluralities of compressibility factor of the formation fluid. The method may further comprise outputting the calculated compressibility factor of the formation fluid.

[0078] In another example embodiment, the method may be performed wherein the molecular weight of C6+ is calculated using a formula of:MC⁢6+=1⁢0⁢7.7⁢5⁢5(1-0.8⁢399⁢ wC⁢6+).

[0079] In another example embodiment, the method may be performed wherein the compressibility factor is calculated using a formula of:Z=PVnRT=MPρ⁢RT.

[0080] In another example embodiment, the method may be performed wherein the outputting of the compressibility factor is at a time during depressurization or pressurization.

[0081] The foregoing description of the embodiments has been provided for purposes of illustration and description. It is not intended to be exhaustive or to limit the disclosure. Individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and can be used in a selected embodiment, even if not specifically shown or described. The same may be varied in many ways. Such variations are not to be regarded as a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.

[0082] While embodiments have been described herein, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments are envisioned that do not depart from the inventive scope. Accordingly, the scope of the present claims or any subsequent claims shall not be unduly limited by the description of the embodiments described herein.

Claims

1. A method for determining a compressibility factor, comprising:disposing a downhole fluid analysis tool within a wellbore;extracting a formation fluid from the wellbore;pumping the formation fluid through the downhole fluid analysis tool;measuring at least one of a flowline temperature, a flowline pressure, a formation fluid mass density, and a pumped volume;measuring compositions (wt %) of CO2, C1, C2, C3, C4, C5 and C6+ (wj, where j=CO2, C1, C2, C3, C4, C5 and C6+) in the formation fluid;estimating pluralities of molecular weight of C6+ in the formation fluid;estimating pluralities of molecular weight of the formation fluid;calculating the compressibility factor of the formation fluid based upon the flowline temperature, the flowline pressure, the formation fluid mass density, and the molecular weight of the formation fluid; andoutputting the compressibility factor of the formation fluid.

2. The method according to claim 1, wherein the molecular weight of the C6+ in the formation fluid is calculated using a formula of:MC⁢6+=1⁢0⁢7.7⁢5⁢5(1-0.8⁢399⁢ wC⁢6+).

3. The method according to claim 1, wherein the molecular weight of the C6+ in the formation fluid is calculated using machine learning methods.

4. The method according to claim 1, wherein the compressibility factor is calculated using a formula of:Z=PVnRT=MPρ⁢RT.

5. The method according to claim 1, wherein the outputting of the compressibility factor is at a time during a sample cleanup.

6. The method according to claim 1, wherein the compositions are determined during a sample cleanup.

7. A method comprising:disposing a downhole fluid analysis tool within a wellbore;extracting a formation fluid from the wellbore;pumping the formation fluid through the downhole fluid analysis tool and to a sample container;obtaining weight percent compositions of CO2, C1, C2, C3, C4, C5 and C6+ in the formation fluid;estimating a molecular weight of the C6+ in the formation fluid;estimating a molecular weight of the formation fluid;performing pressure-density measurements on the formation fluid using one of depressurization in the downhole fluid analysis tool or pressurization at the sample container;obtaining pluralities of temperature, pressure, and formation fluid mass density;calculating pluralities of compressibility factor of the formation fluid; andoutputting the calculated compressibility factor of the formation fluid.

8. The method according to claim 7, wherein the molecular weight of the C6+ in the formation fluid is calculated using a formula of:MC⁢6+=1⁢0⁢7.7⁢5⁢5(1-0.8⁢399⁢ wC⁢6+).

9. The method according to claim 1, wherein the compressibility factor is calculated using a formula of:Z=PVnRT=MPρ⁢RT.

10. The method according to claim 7, wherein the outputting of the compressibility factor is at a time during depressurization or pressurization.

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