Downhole Fluid Analysis Method And Apparatus For Determining Hydrogen Indexes

Abstract

The present disclosure relates to determining hydrogen indexes of downhole fluids using fluid composition data. In certain embodiments, the type of the fluid, such as gas, water, or oil, may be determined downhole and used to select a method for determining the hydrogen index of the fluid. The selected method may then be employed while the tool is downhole to calculate the hydrogen index of the fluid.

Description

BACKGROUND OF THE DISCLOSURE

Wellbores (also known as boreholes) are drilled to penetrate subterranean formations for hydrocarbon prospecting and production. During drilling operations, evaluations may be performed of the subterranean formation for various purposes, such as to locate hydrocarbon-producing formations and manage the production of hydrocarbons from these formations. To conduct formation evaluations, the drill string may include one or more drilling tools that test and/or sample the surrounding formation, or the drill string may be removed from the wellbore, and a wireline tool may be deployed into the wellbore to test and/or sample the formation. These drilling tools and wireline tools, as well as other wellbore tools conveyed on coiled tubing, drill pipe, casing or other conveyers, are also referred to herein as “downhole tools.”

Formation evaluation may involve drawing fluid from the formation into a downhole tool for testing and/or sampling. Various devices, such as probes and/or packers, may be extended from the downhole tool to isolate a region of the wellbore wall, and thereby establish fluid communication with the subterranean formation surrounding the wellbore. Fluid may then be drawn into the downhole tool using the probe and/or packer. Within the downhole tool, the fluid may be directed to one or more fluid analyzers and sensors that may be employed to detect properties of the fluid while the downhole tool is stationary within the wellbore.

SUMMARY

The present disclosure relates to a downhole fluid analysis method that includes analyzing formation fluid within a fluid analyzer of a downhole tool to determine properties of the formation fluid. The method further includes determining a type of the formation fluid based on the determined properties of the formation fluid and selecting a method for calculating a hydrogen index of the formation fluid based on the determined type of the formation fluid. The method also includes calculating the hydrogen index of the formation fluid using the selected method while the downhole tool is disposed within a wellbore.

The present disclosure also relates to a downhole tool that includes a fluid analyzer to determine properties of formation fluid and a controller. The controller is designed to execute instructions stored within the downhole tool to determine a type of the formation fluid based on the determine properties and calculate a hydrogen index of the formation fluid using a method selected based on the determined type of the formation fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of an embodiment of a wellsite system that may employ downhole fluid analysis methods for determining hydrogen indexes, according to aspects of the present disclosure;

FIG. 2 is a schematic view of another embodiment of a wellsite system that may employ downhole fluid analysis methods for determining hydrogen indexes, according to aspects of the present disclosure;

FIG. 3 is a schematic representation of an embodiment of a downhole tool that may employ downhole fluid analysis methods for determining hydrogen indexes, according to aspects of the present disclosure; and

FIG. 4 is a flowchart depicting a fluid analysis method for determining hydrogen indexes, according to aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the present disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting.

The present disclosure relates to methods for determining hydrogen indexes of downhole fluids using fluid composition data obtained by the downhole tool. According to certain embodiments, the hydrogen indexes may be determined in substantially real-time as formation fluid is directed through a fluid analyzer of the downhole tool. In certain embodiments, the type of the fluid, such as gas, water, or oil, may be determined downhole and used to select a method for determining the hydrogen index of the fluid. The selected method may then be employed while the tool is downhole to calculate the hydrogen index of the fluid. In one example, if the fluid type is water, resistivity measurements may be used to calculate the hydrogen index. In another example, if the fluid type is gas, carbon fractions and density measurements provided by the fluid analyzer may be used to calculate the hydrogen index. In a further example, if the fluid type is oil (e.g., live oil), delumped carbon fractions provided by the fluid analyzer may be used to calculate the hydrogen index.

FIGS. 1 and 2 depict examples of wellsite systems that may employ the fluid analysis systems and techniques described herein. FIG. 1 depicts a rig 100 with a downhole tool 102 suspended therefrom and into a wellbore 104 via a drill string 106. The downhole tool 100 has a drill bit 108 at its lower end thereof that is used to advance the downhole tool into the formation and form the wellbore. The drillstring 106 is rotated by a rotary table 110, energized by means not shown, which engages a kelly 112 at the upper end of the drillstring 106. The drillstring 106 is suspended from a hook 114, attached to a traveling block (also not shown), through the kelly 112 and a rotary swivel 116 that permits rotation of the drillstring 106 relative to the hook 114. The rig 100 is depicted as a land-based platform and derrick assembly used to form the wellbore 104 by rotary drilling. However, in other embodiments, the rig 100 may be an offshore platform.

Drilling fluid or mud 118 is stored in a pit 120 formed at the well site. A pump 122 delivers the drilling fluid 118 to the interior of the drillstring 106 via a port in the swivel 116, inducing the drilling fluid to flow downwardly through the drillstring 106 as indicated by a directional arrow 124. The drilling fluid exits the drillstring 106 via ports in the drill bit 108, and then circulates upwardly through the region between the outside of the drillstring and the wall of the wellbore, called the annulus, as indicated by directional arrows 126. The drilling fluid lubricates the drill bit 108 and carries formation cuttings up to the surface as it is returned to the pit 120 for recirculation.

The downhole tool 102, sometimes referred to as a bottom hole assembly (“BHA”), may be positioned near the drill bit 108 and includes various components with capabilities, such as measuring, processing, and storing information, as well as communicating with the surface. A telemetry device (not shown) also may be provided for communicating with a surface unit (not shown).

The downhole tool 102 further includes a sampling system 128 including a fluid communication module 130 and a sampling module 132. The modules may be housed in a drill collar for performing various formation evaluation functions, such as pressure testing and sampling, among others. According to certain embodiments, the sampling system 128 may be employed “while drilling,” meaning that the sampling system 128 may be operated during breaks in operation of the mud pump 122 and/or during breaks in operation of the drill bit 108. As shown in FIG. 1, the fluid communication module 130 is positioned adjacent the sampling module 132; however the position of the fluid communication module 130, as well as other modules, may vary in other embodiments. Additional devices, such as pumps, gauges, sensor, monitors or other devices usable in downhole sampling and/or testing also may be provided. The additional devices may be incorporated into modules 130 and 132 or disposed within separate modules included within the sampling system 128.

The fluid communication module 130 includes a probe 134, which may be positioned in a stabilizer blade or rib 136. The probe 134 includes one or more inlets for receiving formation fluid and one or more flowlines (not shown) extending into the downhole tool for passing fluids through the tool. In certain embodiments, the probe 134 may include a single inlet designed to direct formation fluid into a flowline within the downhole tool. Further, in other embodiments, the probe may include multiple inlets that may, for example, be used for focused sampling. In these embodiments, the probe may be connected to a sampling flow line, as well as to guard flow lines. The probe 134 may be movable between extended and retracted positions for selectively engaging a wall of the wellbore 104 and acquiring fluid samples from the formation F. One or more setting pistons 138 may be provided to assist in positioning the fluid communication device against the wellbore wall.

FIG. 2 depicts an example of a wireline downhole tool 200 that may employ the systems and techniques described herein. The downhole tool 200 is suspended in a wellbore 202 from the lower end of a multi-conductor cable 204 that is spooled on a winch at the surface. The cable 204 is communicatively coupled to an electronics and processing system 206. The downhole tool 200 includes an elongated body 208 that houses modules 210, 212, 214, 222, and 224, that provide various functionalities including fluid sampling, fluid testing, operational control, and communication, among others. For example, the modules 210 and 212 may provide additional functionality such as fluid analysis, resistivity measurements, operational control, communications, coring, and/or imaging, among others.

As shown in FIG. 2, the module 214 is a fluid communication module 214 that has a selectively extendable probe 216 and backup pistons 218 that are arranged on opposite sides of the elongated body 208. The extendable probe 216 is configured to selectively seal off or isolate selected portions of the wall of the wellbore 202 to fluidly couple to the adjacent formation 220 and/or to draw fluid samples from the formation 220. The probe 216 may include a single inlet or multiple inlets designed for guarded or focused sampling. The formation fluid may be expelled to the wellbore through a port in the body 208 or the formation fluid may be sent to one or more fluid sampling modules 222 and 224. The fluid sampling modules 222 and 224 may include sample chambers that store the formation fluid. In the illustrated example, the electronics and processing system 206 and/or a downhole control system are configured to control the extendable probe assembly 216 and/or the drawing of a fluid sample from the formation 220.

FIG. 3 is a schematic diagram of a portion of a downhole tool 300 that may employ the fluid analysis methods described herein. For example, the downhole tool 300 may be a drilling tool, such as the downhole tool 102 described above with respect to FIG. 1. Further, the downhole tool 300 may be a wireline tool, such as the downhole tool 200 described above with respect to FIG. 2. Further, in other embodiments, the downhole tool may be conveyed on wired drill pipe, a combination of wired drill pipe and wireline, or other suitable types of conveyance.

As shown in FIG. 3, the downhole tool 300 includes a fluid communication module 304 that has a probe 306 for directing formation fluid into the downhole tool 300. According, to certain embodiments, the fluid communication module 304 may be similar to the fluid communication modules 130 and 214, described above with respect to FIGS. 1 and 2, respectively. The fluid communication module 304 includes a probe flowline 306 that directs the fluid to a primary flowline 308 that extends through the downhole tool 300. A resistivity sensor 309 may be disposed in the probe flowline 306 to measure the resistivity of the formation fluid. The fluid communication module 304 also includes a pump 310 and pressure gauges 312 and 314 that may be employed to conduct formation pressure tests. An equalization valve 316 may be opened to expose the flowline 306 to the pressure in the wellbore, which in turn may equalize the pressure within the downhole tool 300. Further, an isolation valve 318 may be closed to isolate the formation fluid within the flowline 306, and may be opened to direct the formation fluid from the probe flowline 306 to the primary flowline 308.

The primary flowline 308 directs the formation fluid through the downhole tool to a fluid analysis module 320 that includes a fluid analyzer 321 can be employed to provide in situ downhole fluid measurements. For example, the fluid analyzer 321 may include an optical spectrometer 322 and/or a gas analyzer 324 designed to measure properties such as, optical density, fluid density, fluid viscosity, fluid fluorescence, fluid composition, and the fluid gas oil ratio (GOR), among others. According to certain embodiments, the spectrometer 332 may include any suitable number of measurement channels for detecting different wavelengths, and may include a filter-array spectrometer or a grating spectrometer. For example, the spectrometer 332 may be a filter-array absorption spectrometer having ten measurement channels. In other embodiments, the spectrometer 322 may have sixteen channels or twenty channels, and may be provided as a filter-array spectrometer or a grating spectrometer, or a combination thereof (e.g., a dual spectrometer), by way of example. According to certain embodiments, the gas analyzer 324 may include one or more photodetector arrays that detect reflected light rays at certain angles of incidence. The gas analyzer 324 also may include a light source, such as a light emitting diode, a prism, such as a sapphire prism, and a polarizer, among other components. In certain embodiments, the gas analyzer 324 may include a gas detector and one or more fluorescence detectors designed to detect free gas bubbles and retrograde condensate liquid drop out.

One or more additional measurement devices 325, such as temperature sensors, pressure sensors, viscosity sensors, chemical sensors (e.g., for measuring pH or H₂S levels), and gas chromatographs, may be included within the fluid analyzer 321. Further, the fluid analyzer 321 may include a resistivity sensor 327 and a density sensor 329, which, for example, may be a densimeter or a densitometer. In certain embodiments, the fluid analysis module 320 may include a controller 326, such as a microprocessor or control circuitry, designed to calculate certain fluid properties based on the sensor measurements. Further, in certain embodiments, the controller 326 may govern sampling operations based on the fluid measurements or properties. Moreover, in other embodiments, the controller 326 may be disposed within another module of the downhole tool 300.

The downhole tool 300 also includes a pump out module 328 that has a pump 330 designed to provide motive force to direct the fluid through the downhole tool 300. According to certain embodiments, the pump 330 may be a hydraulic displacement unit that receives fluid into alternating pump chambers. A valve block 332 may direct the fluid into and out of the alternating pump chambers. The valve block 332 also may direct the fluid exiting the pump 330 through the remainder of the primary flowline (e.g., towards the sample module 336) or may divert the fluid to the wellbore through an exit flowline 334.

The downhole tool 300 also includes one or more sample modules 336 designed to store samples of the formation fluid within sample chambers 338 and 340. The sample module 336 includes valves 342 and 344 that may be actuated to divert the formation fluid into the sample chambers 338 and 340. The sample chambers 338 and 340 also may include respective valves 346 and 348 that can be opened to expose a volume 350 of the sample chambers 338 and 340 to the annular pressure. In certain embodiments, the valve 346 or 348 may be opened to allow buffer fluid to exit the volume 350 to the wellbore, which may provide backpressure during filling of a volume 352 that receives formation fluid. According to certain embodiments, the volume 352, which may store formation fluid, may be separated from the volume 350 by a floating piston 354.

The valve arrangements and module arrangements described herein are provided by way of example, and are not intended to be limiting. For example, the valves described herein may include valves of various types and configurations, such as ball valves, gate valves, solenoid valves, check valves, seal valves, two-way valves, three-way valves, four-way valves, and combinations thereof, among others. Further, in other embodiments, different arrangements of valves may be employed. For example, the valves 342 and 344 may be replaced by a single valve. Moreover, in certain embodiments, the respective positions of the modules 304, 320, 328, and 336 may vary. For example, in other embodiments, the fluid analysis module 320 may be disposed between the pump out module 328 and the sample module 336, rather than between the pump out module 328 and the probe module 304 as shown in FIG. 3. Moreover, other types of sample chambers, such as single phase sample bottles, among others, may be employed in one or more sample modules 336.

FIG. 4 is a flowchart depicting an embodiment of a method 400 that may be employed to determine hydrogen indexes of formation fluid. As used herein, hydrogen index (HI) is defined as the ratio between the amount of hydrogen in a given volume of a fluid (e.g., formation fluid) and the amount of hydrogen in the same volume of pure water at standard temperature and pressure conditions (STP). The HI may be represented by Equation 1 as follows:

$\begin{array}{cc}\begin{array}{c}\mathrm{HI}\equiv \frac{\mathrm{Amount}\mathrm{of}\mathrm{Hydrogen}\mathrm{in}\mathrm{Formation}\mathrm{Fluid}}{\mathrm{Amount}\mathrm{of}\mathrm{Hydrogen}\mathrm{in}\mathrm{Pure}\mathrm{Water}\mathrm{at}\mathrm{STP}}\\ =\frac{\mathrm{atoms}\mathrm{of}\mathrm{Hydrogen}/{\mathrm{cm}}^3\mathrm{of}\mathrm{fluid}}{\mathrm{atoms}\mathrm{of}\mathrm{Hydrogen}/{\mathrm{cm}}^3\mathrm{of}\mathrm{water}\mathrm{at}\mathrm{STP}}\\ =\frac{{\rho }_mN_H/M}{0.111}\end{array}& \mathrm{Eq}.\left(1\right)\end{array}$

where ρ_m is the mass density of the fluid in g/cm³; N_H is the number of hydrogen atoms per mole of the fluid; M is the molecular weight of the fluid in gm/mole; and 0.111 represents the number of hydrogen atoms in one cubic centimeter of water at standard conditions.

According to certain embodiments, the method 400 may be executed, in whole or in part, by the controller 326 (FIG. 3). For example, the controller 326 may execute code stored within circuitry of the controller 326, or within a separate memory or other tangible readable medium, to perform the method 400. In certain embodiments, the method 400 may be wholly executed while the tool 300 is disposed within a wellbore, allowing a substantially real-time determination of the hydrogen index of the formation fluid. Further, in certain embodiments, the controller 326 may operate in conjunction with a surface controller, such as the processing system 206 (FIG. 2), that may perform one or more operations of the method 400.

The method 400 may begin by analyzing (block 402) the formation fluid. For example, the formation fluid may be withdrawn into the downhole tool 300 through the probe 305 and analyzed within the fluid analyzer 321, as described above with respect to FIG. 3. In certain embodiments, the fluid analyzer 321 may measure the absorption spectra and translate the measurements into the concentrations of water (H₂O), carbon dioxide (CO₂), methane (C₁), ethane (C₂H₆), the C₃-C₅ alkane group including propane, butane, and pentane, and the lump of hexane and heavier alkane components (C₆₊), among others. The fluid analyzer 321 may then employ the foregoing compositional information to determine additional fluid properties, such as the condensate yield and the gas-oil-ratio (GOR), among others. In certain embodiments, the controller 326 may operate in conjunction with the fluid analyzer 321 to determine the additional fluid properties using the composition information received from the fluid analyzer 321. The fluid analyzer 321 also may measure the density and resistivity of the fluid, for example, using the density resistivity sensor 327 and the density sensor 329. Further, in other embodiments, the fluid analyzer 321 or the controller 326 may receive the resistivity from the resistivity sensor 309 included within the fluid communication module 304. Additional details of fluid analysis techniques and methods that may be employed to analyze (block 402) the formation fluid are described in the following commonly assigned U.S. Pat. No. 8,434,356 to Hsu et al.; U.S. Pat. No. 7,920,970 to Zuo et al.; U.S. Pat. No. 7,822,554 to Zuo et al.; U.S. Pat. No. 7,526,953 to Goodwin et al.; U.S. Pat. No. 6,476,384 to Mullins et al; U.S. Pat. No. 5,331,156 to Hines et al.; and U.S. Pat. No. 4,994,671 to Safinya et al.; which are each herein incorporated by reference in their entirety.

The method may then continue by determining (block 404) the type of the formation fluid (e.g., water, gas, or live oil). For example, the controller 326 may determine the fluid type based on the composition information and the additional fluid properties, such as the GOR and the water concentration, among others, provided by the fluid analyzer 321. Additional details of fluid typing may be found in commonly assigned U.S. Pat. No. 8,434,356 to Hsu et al.; U.S. Pat. No. 7,920,970 to Zuo et al.; U.S. Pat. No. 7,822,554 to Zuo et al.; U.S. Pat. No. 7,526,953 to Goodwin et al.; U.S. Pat. No. 6,476,384 to Mullins et al; U.S. Pat. No. 5,331,156 to Hines et al.; and U.S. Pat. No. 4,994,671 to Safinya et al, previously incorporated by reference.

If the fluid type is water (e.g. a brine or other water-based solution or fluid), the controller 326 may determine the HI (block 406) using the water resistivity measured by the resistivity sensor 327 or 309. For example, the controller 326 may employ one or more lookup tables or algorithms, which correlate the water resistivity to the HI, to determine the HI for formation fluid of the water type.

If the fluid type is gas, the controller 326 may determine the HI (block 408) based on the density of the gas, and the concentrations, such as the methane, ethane, propane, butane, pentane, and CO₂ concentrations, among others, determined using the fluid analyzer 321. Accordingly to certain embodiments, the fluid analyzer measures the individual concentrations of the methane, ethane and CO₂ and the lumped concentration of the C₃ through C₅ components (propane, butane, pentane and their isomers). The C₃ through C₅ composite concentration can then be split into the individual carbon component concentrations using a ratio rule or other empirical correlations known to those skilled in the art. For example, a ratio rule such as a 3:2:1 ratio of C₃:C₄:C₅ can be employed where the C₃ through C₅ concentration is divided into 3 parts C₃ components, 2 parts C₄ components, and 1 part C₅ components. In other embodiments, the composite concentration may represent another range of carbon components, such as a C₂ through C₄ composite concentration, among others, that can be split into the individual carbon component concentrations.

For computing the hydrogen index, Equation 1 may be expanded for gas mixtures, as shown in Equation 2 below:

$\begin{array}{cc}\mathrm{HI}=\frac{\mathrm{atoms}\mathrm{of}\mathrm{Hydrogen}/{\mathrm{cm}}^3\mathrm{of}\mathrm{gas}\mathrm{mixture}}{0.111}=\frac{\sum _i^n{\tilde{\rho }}_iN_{H,i}}{0.111}\mathrm{HI}=\frac{\stackrel{\_}{\rho }\sum _i^ny_iN_{H,i}}{0.111}& \mathrm{Eq}.\left(2\right)\end{array}$

where, {tilde over (ρ)}_i represents the partial molar density of the ith component of the gas mixture; N_H,i represents the number of hydrogen atoms per molecule of the ith component; γ_i represents the mole fraction of the ith component; and ρ represents the average molar density of the gas mixture in mole/cc. The mole fraction of each component (γ_i) is determined from the composition information and density measured on the gas in situ, using the fluid analyzer 321. The average molar density ρ of the gas mixture is computed using equation 3 as follows:

$\begin{array}{cc}\stackrel{\_}{\rho }=\frac{{\rho }_m}{\sum _i^ny_iMW_i}& \mathrm{Eq}.\left(3\right)\end{array}$

where, ρ_m is the mass density of the gas (in gm/cc), as measured downhole by the fluid analyzer 321; and MW_i is the theoretical molecular weight of the ith component of the gas mixture in gm/mole.

If the fluid type is live oil, the controller 326 may determine the HI by using the concentrations, such as the methane and ethane concentrations and the C₃-C₅ and C₆₊ composite concentrations, among others, determined using the fluid analyzer 321. For example, the controller 326 may employ the methane and ethane concentrations directly and then delump (block 410) the componsite concentrations, such as the C₃-C₅ and C₆₊ concentrations, that are measured by the fluid analyzer 321. In other embodiments, the composite concentration may represent another range of carbon components, such as a C₂ through C₄ composite concentration, among others, that can be delumped into the individual carbon component concentrations.

In certain embodiments, the controller 326 may execute algorithms that determine the composition of the formation fluid, broken down by each carbon number component rather than by the grouping of certain carbon components, based on an empirical relationship developed using a historical PVT database. The PVT database may store the weight percentage, molecular weight, molar percentage, and specific gravity of single carbon number alkane components, as well as PVT properties (e.g, GOR, API gravities, formation volume factor (FVF), densities, and viscosities) for a large number of samples from different petroleum reservoirs throughout the world. The weight percentage for each component (e.g., each carbon number component) may be derived based on the information from the fluid analyzer 321 and the empirical relation derived from analysis of the PVT database. Additional details of the delumping process are described in U.S. Pat. No. 7,920,970 to Zuo et al., previously incorporated by reference. The results of the delumping process provide the composition of the formation fluid, such as the mole or weight percentage for each carbon number component in the formation fluid.

The delumping results can then be employed to determine (block 412) the average number of hydrogen atoms per mole of the live oil mixture, N_H and to determine (block 414) the molecular weight, MW of the live oil mixture as follows:

$\begin{array}{cc}\stackrel{\_}{N_H}=\sum _i^ny_iN_{H,i}& \mathrm{Eq}.\left(4\right)\\ \stackrel{\_}{MW}=\sum _i^ny_iMW_i.& \mathrm{Eq}.\left(5\right)\end{array}$

where, N_H,i represents the number of hydrogen atoms per molecule of the ith component; γ_i represents the mole fraction of the ith component; and MW_i is the theoretical molecular weight of the ith component of the gas mixture in gm/mole.

These values can then be employed in Equation 6 to determine the HI as follows:

$\begin{array}{cc}\mathrm{HI}=\frac{{\rho }_m\stackrel{\_}{N_H}}{0.111*\stackrel{\_}{MW}}& \mathrm{Eq}.\left(6\right)\end{array}$

where, ρ_m is the mass density of the gas (in gm/cc), as measured downhole by the fluid analyzer 321.

According to certain embodiments, the hydrogen index (HI) may be used to calibrate nuclear magnetic resonance (NMR) porosity measurements. For example, the porosity response of NMR porosity tools is directly proportional to the HI of the volume sensed by the tool. The tools are calibrated to water at standard conditions, which corresponds to a HI equal to 1. Accordingly, the porosity measured and output by these tools is representative of the true formation porosity when the formation fluid in the sensed volume has a HI approximately equal to 1. However, the HI obtained using the methods described herein may be employed to calibrate the NMR porosity measurements provided by the tools using the following Equation 7:

$\begin{array}{cc}\mathrm{True}\mathrm{Porosity}=\frac{\mathrm{Measured}\mathrm{Porosity}}{\mathrm{HI}}& \mathrm{Eq}.\left(7\right)\end{array}$

Using Equation 7, the HI obtained by the method 400 may be employed to calibrate the porosity obtained by NMR porosity tools at the wellsite. The foregoing provides one example of an application for the HI obtained by the techniques described herein, and is not intended to be limiting. The HI's obtained using the methods described herein may be employed for any suitable reservoir characterization and/or downhole fluid analysis applications.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

Claims

1. A downhole fluid analysis method comprising: analyzing formation fluid within a fluid analyzer of a downhole tool to determine properties of the formation fluid;determining a type of the formation fluid based on the determined properties of the formation fluid;selecting a method for calculating a hydrogen index of the formation fluid based on the determined type of the formation fluid; andcalculating the hydrogen index of the formation fluid using the selected method while the downhole tool is disposed within a wellbore.

2. The downhole fluid analysis method of claim 1, wherein analyzing comprises measuring an absorption spectra of the formation fluid.

3. The downhole fluid analysis method of claim 1, wherein analyzing comprises measuring a resistivity of the formation fluid or a density of the formation fluid, or both.

4. The downhole fluid analysis method of claim 1, wherein analyzing comprises determine concentrations of components within the formation fluid.

5. The downhole fluid analysis method of claim 1, wherein determining comprises determining whether the formation fluid is a water-based fluid, a gas, or a live oil.

6. The downhole fluid analysis method of claim 1, wherein selecting comprises selecting the method from a first method for a water-based fluid, a second method for a gas, and a third method for a live oil.

7. The downhole fluid analysis method of claim 6, wherein the first method computes the hydrogen index based on a measured resistivity of the formation fluid.

8. The downhole fluid analysis method of claim 6, wherein the second method computes the hydrogen index based on a density of the formation fluid and concentrations of components of the formation fluid.

9. The downhole fluid analysis method of claim 6, wherein the third method computes the hydrogen index based on delumped C3-C5 and C6+ concentrations.

10. The downhole fluid analysis method of claim 1, further comprising using the calculated hydrogen index to calibrate a porosity measurement.

11. A downhole tool comprising: a fluid analyzer to determine properties of formation fluid; anda controller configured to execute instructions stored within the downhole tool to: determine a type of the formation fluid based on the determined properties; andcalculate a hydrogen index of the formation fluid using a method selected based on the determined type of the formation fluid.

12. The downhole tool of claim 11, wherein the fluid analyzer comprises an optical spectrometer, or a gas chromatograph, or both.

13. The downhole tool of claim 11, wherein the controller is configured to execute the instructions to determine a gas oil ratio of the formation fluid.

14. The downhole tool of claim 11, wherein the fluid analyzer comprises a resistivity sensor for measuring a resistivity of the formation fluid, and wherein the controller is configured to execute the instructions to calculate the hydrogen index, based on the measured resistivity, in response to determining that the type of the formation fluid is a water-based fluid.

15. The downhole tool of claim 11, wherein the fluid analyzer comprises a density sensor for measuring a density of the formation fluid, and wherein the controller is configured to execute the instructions to calculate the hydrogen index, based on the measured density, in response to determining that the type of the formation fluid is a gas.

16. The downhole tool of claim 11, wherein the fluid analyzer comprises an optical spectrometer for measuring an absorption spectra of the formation fluid, and wherein the controller is configured to execute the instructions to calculate the hydrogen index based on the measured absorption spectra in response to determining that the type of the formation fluid is a gas or a live oil.

17. The downhole tool of claim 11, wherein the controller is configured to execute the instructions to delump concentrations of carbon components in response to determining the type of formation fluid is a live oil.

18. The downhole tool of claim 11, further comprising a probe module configured to direct the formation fluid into the downhole tool.

19. The downhole tool of claim 18, wherein the probe module comprises a resistivity sensor for measuring a resistivity of the formation fluid, and wherein the controller is configured to execute the instructions to calculate the hydrogen index, based on the measured resistivity, in response to determining that the type of the formation fluid is a water-based fluid.

20. The downhole tool of claim 11, further comprising a sample module configured to store the formation fluid.