US20130239671A1

US20130239671A1 - Pressure-corrected density of a fluid

Info

Publication number: US20130239671A1
Application number: US13/420,929
Authority: US
Inventors: Adriaan Gisolf; Peter S. Hegeman; Vladislav Achourov; Thomas Pfeiffer; Michael O'Keefe
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2012-03-15
Filing date: 2012-03-15
Publication date: 2013-09-19
Also published as: WO2013138119A1

Abstract

This disclosure is drawn to methods, systems, devices and/or apparatus related to determining the density of a fluid. Specifically, the disclosed methods, systems, devices and/or apparatus relate to determining the density of a fluid in situ (e.g., in a downhole tool) under the Earth's surface using extrapolation and/or interpolation technique(s). Some example methods may include obtaining a fluid sample from a formation, measuring, in a downhole tool, a plurality of density values of the fluid sample, each density value being measured at a distinct pressure level within a pressure range, and extrapolating and/or interpolating the plurality of density values of the fluid sample to a pressure level different that the distinct pressure in which the density value is measured. Some example methods may include tuning one or more Equation-of-State model based, at least in part, on the density values.

Description

BACKGROUND

In reservoir engineering, the density of formation fluid is used for many purposes. The value of the formation fluid density is used to reduce the number of pressure measurements needed to achieve a precise and accurate pressure gradient, and to identify compositional grading. This value is also used in Equation-of-State (EOS) modeling, and to obtain a value of the pressure gradient in a thinly layered reservoir. Further, this value is used for other purposes, including monitoring formation fluid contamination during sampling. The measurement of the formation fluid density can be performed in a downhole tool, such as a modular dynamics formation tester (MDT).
In the MDT, the density sensor is often run downstream of the pump, where the sensor is exposed to hydrostatic pressure. In other downhole tools, the density sensor is often used in a micro fluidic channel coupled to a hydrophobic membrane, where the sensor is exposed to the pressure used to flow hydrocarbons in the micro fluidic channel. Most fluid density applications require a fluid density value representative of static reservoir conditions. When the value of the fluid density is desired at a given pressure level, and the value of the fluid density is measured at other pressure levels, the measured density value(s) have to be pressure corrected to reflect fluid compression between pressure levels. For lean and dry gases in high over-balance, the density correction can be very large (e.g., 50%).

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other features of the present disclosure will become more fully apparent from the following description and appended claims, taken in conjunction with the accompanying drawings. Understanding that these drawings depict several embodiments in accordance with the disclosure and are, therefore, not to be considered limiting of its scope, the disclosure will be described with additional specificity and detail through use of the accompanying drawings.

In the drawings:

FIG. 1 is a flowchart depicting an example method for determining a density of a fluid in a formation;

FIG. 2 is a flowchart depicting another example method for determining a density of a fluid in a formation;

FIG. 3 depicts an example system that may be used to acquire data points of pressure versus density to determine a density of a fluid in a formation;

FIG. 4 depicts another example system that may be used to acquire data points of pressure versus density to determine a density of a fluid in a formation;

FIG. 5 is a graph depicting example pressure and density data measured at distinct times when the pressure of a fluid sample is adjusted;

FIG. 6 is a graph depicting data points (density versus pressure) corresponding to the example pressure and density data depicted in FIG. 5; and

FIG. 7 is a graph depicting data points (density versus the log of pressure) corresponding to example pressure and density data measured while filling and over-pressuring two gas sample bottles, each arranged in accordance with at least an embodiment of the present disclosure.

DETAILED DESCRIPTION

In the following detailed description, reference is made to the accompanying drawings, which form a part hereof. In the drawings, similar symbols identify similar components, unless context dictates otherwise. The illustrative embodiments described in the detailed description and drawings are not meant to be limiting and are for explanatory purposes. Other embodiments may be utilized, and other changes may be made, without departing from the spirit or scope of the subject matter presented herein. It will be readily understood that the aspects of the present disclosure, as generally described herein, and illustrated in the drawings, may be arranged, substituted, combined, and designed in a wide variety of different configurations, each of which are explicitly contemplated and made part of this disclosure.
This disclosure is drawn to methods, systems, devices and/or apparatus related to determining the density of a fluid. Specifically, the disclosed methods, systems, devices and/or apparatus relate to determining the density of a fluid in situ under the Earth's surface using extrapolation and/or interpolation technique(s).
FIG. 1 is a flowchart depicting an example method 100 of determining a density of a fluid in a formation, in accordance with at least an embodiment of the present disclosure. Example method 100, as depicted in FIG. 1, may include obtaining 110 a fluid sample from a formation. Example method 100 may further include measuring 120, in a downhole tool, density values of the fluid sample, where each density value may be measured at a distinct pressure level within a pressure range. Example method 100 may further include extrapolating and/or interpolating the density values of the fluid sample to a pressure level different that the distinct pressure in which the density value is measured.
In some examples, extrapolating the density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured includes extrapolating the density values to the pressure level outside of the pressure range. In some examples, interpolating the density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured includes interpolating the density values to the pressure level inside of the pressure range.
In some examples, methods may include measuring a first density value at a first pressure level within the pressure range. The first pressure level may be altered to a second pressure level within the pressure range. Further, a second density value may be measured at the second pressure level. In some examples, methods may include extrapolating and/or interpolating the first density value and the second density value. In some examples, methods may further include determining a third density value at a third pressure level outside of the pressure range based, at least in part, on extrapolating the first density value and the second density value. In some examples, methods may further include determining a third density value at a third pressure level inside of the pressure range based, at least in part, on interpolating the first density value and the second density value.
In some examples, the pressure level includes a formation pore pressure level which may be measured with a pretest at the location the fluid sample is being extracted. In some examples, the pressure level may be known and/or chosen arbitrarily as a reference pressure level.
In some examples, the fluid sample contained in a flow line may be compressed and/or decompressed using a pump or a pretest piston. The pressure and density of the fluid sample may be measured substantially continuously at distinct times during the fluid sample compression and/or decompression.
In some examples, some measurements (e.g., first density value, second density value) may be measured when the fluid sample is in situ under the Earth's surface (e.g., in a downhole tool) and/or on the Earth's surface. In some examples, some extrapolated and/or interpolated values (e.g., third density value) may be determined in situ under the Earth's surface and/or on the Earth's surface. In some examples, the density values of the fluid sample may be measured using a vibrating rod, a tuning fork, a vibrating tube and/or other device or system capable of measuring density. In some examples, the pressure level may include a formation pore pressure level, a predetermined pressure level, and/or an arbitrary pressure level. In some examples, each respective pressure level may be determined by a crystal quartz gauge, a silicon-on-isolator gauge, a strain gauge, and/or other device capable of measuring pressure.
In some examples, extrapolating may include linear extrapolation and/or logarithmic extrapolation techniques. Some examples may include linearly and/or logarithmically extrapolating the density values to the pressure level outside the pressure range based on the type of fluid being sampled and/or measured. For example, when the density of water or oil is measured, linear extrapolation technique(s) may be used (e.g., the curve of the data points—density versus pressure—may be approximated by a linear function). When the density of a gas is being measured, logarithmic extrapolation technique(s) may be used (e.g., the curve of the data points—density versus the logarithm of the pressure—may be approximated by a logarithmic function). In some examples, data points (e.g., density versus pressure) may be displayed to a user and the user may choose which extrapolation function(s) to use on the data points. Some examples may include linearly and/or logarithmically extrapolating regardless of the type of fluid being sampled and/or measured.
In some examples, interpolating may include linear interpolation and/or logarithmic interpolation techniques. Some examples may include linearly and/or logarithmically interpolating the density values to the pressure level based on the type of fluid being sampled and/or measured. Some examples may include linearly and/or logarithmically interpolating regardless of the type of fluid being sampled and/or measured.
FIG. 2 is a flowchart depicting another example method 200 of determining a density of a fluid in a formation, in accordance with at least an embodiment of the present disclosure. Example method 200, as depicted in FIG. 2, may include measuring 210 a first fluid density value of a fluid sample at a first pressure. Example method 200 may further include altering 220 (e.g., increasing, decreasing) the first pressure to a second pressure different than the first pressure. Example method 200 may further include measuring 230 a second fluid density value of the fluid sample at the second pressure. Example method 200 may further include extrapolating and/or interpolating 240 a third fluid density value at a third pressure based (at least in part) on the first fluid density value at the first pressure and the second fluid density value at the second pressure. The third pressure may be different than the first pressure and the second pressure. In some examples, the third pressure may represent a formation pore pressure level, a predetermined pressure level, and/or an arbitrary pressure level.
As a non-limiting example, the present disclosure contemplates that downhole fluid analyzers may measure the compositional data (e.g., weight percentage) of fluid in hydrocarbon component groups, such as methane (C1), ethane (C2), the group comprising propane, butane, and pentane (C3-05), the group hexane and heavier (C6+), and carbon dioxide (CO₂).
In some examples, method 200 may further include delumping downhole fluid analysis (DFA) data associated with the fluid sample to compositional data, such as full-length compositional data. Method 200 may further include establishing Equation-of-State (EOS) model(s) based (at least in part) on the compositional data. Further, example method 200 may include tuning the EOS model(s) based (at least in part) on the third fluid density value. Example method 200 may further include verifying the third density value with the EOS model(s). Example method 200 may further include correcting the third density value based (at least in part) on a temperature of the fluid sample and a contamination of the fluid sample.
FIG. 3 depicts an example system 300 that may be used to acquire data points of pressure versus density to determine a density of a fluid in a formation, in accordance with at least an embodiment of the present disclosure. Example system 300 may include an apparatus 34 for determining a density of a fluid in a formation 20. Example apparatus 34 may include a fluid chamber 60 adapted to at least temporarily hold a fluid sample extracted from the formation 20. The fluid sample may be captured and/or stored in fluid chamber 60 via valves 70, 72. Example apparatus 34 may also include pressure regulator(s) 64 adapted to regulate a pressure applied to the fluid sample between a first pressure and a second pressure, where the first pressure is different than the second pressure. Similarly, piston 86 may operate to alter the pressure of the fluid sample in the fluid chamber 60. Pressure gauge(s) 66 a may measure the pressure applied to the fluid sample in the fluid chamber 60 at the first and second pressures. Density sensor(s) 66 b may measure the density of the fluid sample in the fluid chamber 60. In some examples, density sensor(s) 66 b may measure the density of the fluid sample when the fluid sample is not in the fluid chamber 60, such as when the fluid sample passes through the flowline. Signal processor(s) 94 (or signal processor(s) located at the surface, not shown) may determine a density of the fluid sample at a third pressure using extrapolation techniques and/or interpolation techniques, where the third pressure is different than the first and second pressures. In this manner, the density of the fluid sample may be determined while the fluid sample is exposed to multiple distinct and different pressure levels.
In some examples, the pressure (i.e., a first pressure level) of the fluid sample in the fluid chamber 60 may be measured using gauge 66 a, and the density of the fluid sample at the first pressure level may be measured and/or determined using sensor 66 b. Then, the first pressure level may be altered by operation of piston 86 to produce a second pressure level of the fluid sample in the evaluation chamber 60. The second pressure level may be higher or lower than the first pressure level. As a non-limiting example, the first pressure level may be at or near formation pore pressure, and the second pressure level may be lower than the formation pore pressure. In another example, the first pressure level may be below formation pore pressure, and the second pressure level may be at or substantially similar to formation pore pressure. These are merely examples and the first and second pressure levels should not be limited to any specific pressure. The second pressure level of the fluid sample in the evaluation chamber 60 may be measured using gauge 66 a, and the density of the fluid sample at the second pressure level may be measured and/or determined using sensor 66 b.
In some examples, the fluid chamber 60, the pressure regulator(s) 64, the pressure gauge(s) 66 a and/or the density sensor(s) 66 b may be housed in a downhole tool. In some examples, the pressure gauge(s) 66 a may generate pressure data representative of the pressure applied to the fluid sample and may store the pressure data in a memory. In some examples, the density sensor(s) 66 b may generate density data representative of the density of the fluid sample and may store the density data in the memory. In some examples, the signal processor(s) 94 and/or memory may be housed in a surface logging unit.
In some examples, the signal processor(s) 94 may extrapolate (e.g., linearly extrapolate) the density of the fluid sample at the pressure level outside of the pressure range (created by the first and second pressures) when the fluid sample is water and/or oil. In some examples, the signal processor(s) 94 may extrapolate (e.g., logarithmically extrapolate) the density of the fluid sample at the pressure level outside of the pressure range (created by the first and second pressures) when the fluid sample is a gas.
In some examples, the signal processor(s) 94 may interpolate (e.g., linearly interpolate) the density of the fluid sample at the pressure level inside of the pressure range (created by the first and second pressures) when the fluid sample is water and/or oil. In some examples, the signal processor(s) 94 may interpolate (e.g., logarithmically interpolate) the density of the fluid sample at the pressure level inside of the pressure range (created by the first and second pressures) when the fluid sample is a gas.
FIG. 4 depicts another example system 400 that may be used to acquire data points of pressure versus density to determine a density of a fluid in a formation, in accordance with at least an embodiment of the present disclosure. A formation fluid sample may be extracted for the formation via probe 201. A person having ordinary skill in the art will appreciate other devices may be used to extract a sample, such as a single packer having a sampling port, and the present disclosure should not be deemed as limited to a probe or other device for obtaining a sample. The fluid sample may be captured and/or stored in one of the sample chambers 62, 63 or 64. Sample chambers 62, 63, 64 may include a sliding piston, one side of which may be exposed to the wellbore 218, and the other side may be operably connected to the pump 41. The fluid sample may be pressurized in the chambers 62, 63, 64 until check valve 74 opens. The pressure of the fluid sample may be measured using gauge 77. Similarly, the density may be measured with density sensor 220.
In some examples, a fluid sample may be captured in the flowline 204 between valves 206 and 208. The pressure level in flowline 204 may be altered using pretest piston 207, and the pressure level may be measured using gauge 210. The density of the fluid sample may be measured using density sensor 222. In this manner, the density of the fluid sample may be measured while the fluid sample is exposed to multiple pressure levels.
FIG. 5 is a graph 500 depicting example pressure and density data obtained at distinct times when the pressure of a fluid sample is adjusted, in accordance with at least an embodiment of the present disclosure. FIG. 5 shows pressure data 502 and density data 504 measured at distinct times when the pressure level of a fluid sample is altered. Specifically, FIG. 5 illustrates pressure and density data obtained from time of 12,280 seconds to time of 12,355 seconds. During this period, the pressure of a fluid sample is increased from 150 to 400 bar. During this period, the density increased from approximately 1.051 g/cm³to 1.061 g/cm³.
FIG. 6 is a graph 600 depicting data points (density versus pressure) corresponding to the example pressure and density data depicted in FIG. 5. FIG. 6 depicts a linear extrapolation function (depicted as line 602). This extrapolation function may then be used to determine and/or estimate the density of the fluid (in this example water and/or oil). FIG. 6 includes such an estimate (depicted as lines 604, 606) for a pressure level of 100 bar. In this example, for a pressure level of 100 bar, the density of the fluid may be estimated as approximately 1.0475 g/cm³. Note that a pressure level of 100 bar is outside the pressure range used to measure densities of the fluid sample between 150 bar and 400 bar (as discussed in relation to FIG. 5).
FIG. 7 is a graph 700 depicting data points (density versus the log of pressure) corresponding to example pressure and density data measured while filling and over-pressuring two gas sample bottles. Density data are recorded at various pressure levels for sample bottle 1 (depicted as 702). Similarly, density data are recorded at various pressure levels for sample bottle 2 (depicted as 704). In this example, the pressure may range from approximately 160 to 680 bar (depicted in FIG. 7 on a logarithmic scale). Also shown is an extrapolation function for sample bottle 1 (depicted as line 712) down to approximately 100 bar and an extrapolation function for sample bottle 2 (depicted as line 714) down to approximately 100 bar. In some examples, the pressure and density data may be combined, allowing extrapolation and/or interpolation of a single combined data set.
In some examples, known segregation apparatus (e.g., membrane(s)) may be used to separate oil from a mixture of water and oil prior to measuring pressure and/or density. In some examples, the fluid sample may have passed through a membrane or otherwise been segregated before the density measurements are performed. Therefore, the fluid sample may contain little or no water. Estimation of contamination by mud filtrate might be obtained by plotting pressure corrected density against time, particularly when the density sensor is located upstream of the pump. Correction of the density value for contamination and/or for temperature may be performed, for example with multi-dimensional fitting (e.g., density versus pumped volume/pressure/temperature). Measurements other than the density, such as absorbance at particular wavelengths in the visible and/or near-infrared ranges may also be fitted with the density, for example, using the same fitting function.
It is contemplated that, in some examples, curve fitting a pressure-density range obtained as indicated should be accurate, even if the sample fluid flows during the density measurement, and even if the flow rate is not stable. In some examples, extrapolation of density values to a “pristine formation fluid” density value at zero contamination may be obtained using known methods. The independent variables of pressure and temperature may be added to the curve fit. In some examples, the temperature variation may be neglected.
Methods of determining a density of a fluid in a formation are disclosed herein. Such examples may include obtaining a fluid sample from a formation, measuring, in a downhole tool, density values of the fluid sample, where each density value is measured at a distinct pressure level within a pressure range, and extrapolating and/or interpolating the density values of the fluid sample to a pressure level different that the distinct pressure in which the density value is measured.
Such examples disclosed herein may also include measuring a first fluid density value of a fluid sample at a first pressure, altering the first pressure to a second pressure different than the first pressure, measuring a second fluid density value of the fluid sample at the second pressure, and extrapolating and/or interpolating a third fluid density value at a third pressure based (at least in part) on the first fluid density value at the first pressure and the second fluid density value at the second pressure. The third pressure is different than the first pressure and the second pressure.
Further, some examples may include apparatus for determining a density of a fluid in a formation. Such examples may include a fluid chamber, pressure regulator(s), pressure gauge(s), density sensor(s), and signal processor(s). The fluid chamber may hold a fluid sample. The pressure regulator(s) may regulate a pressure applied to the fluid sample between a first pressure and a second pressure, where the first pressure is different than the second pressure. The pressure gauge(s) may measure the pressure applied to the fluid sample in the fluid chamber. The density sensor(s) may measure the density of the fluid sample at the first pressure and the second pressure. The signal processor(s) may determine a density of the fluid sample at a third pressure via extrapolation technique(s) and/or interpolation technique(s), where the third pressure is different than the first pressure and the second pressure.
While various aspects and embodiments have been disclosed herein, other aspects and embodiments will be apparent to those skilled in the art. The various aspects and embodiments disclosed herein are for purposes of illustration and are not intended to be limiting, with the true scope and spirit being indicated by the following claims.

Claims

What is claimed is:

1. A method of determining a density of a fluid in a formation, the method comprising:

obtaining a fluid sample from a formation;

measuring, in a downhole tool, a plurality of density values of the fluid sample, each density value being measured at a distinct pressure level within a pressure range; and

at least one of extrapolating and interpolating the plurality of density values of the fluid sample to a pressure level different that the distinct pressure in which the density value is measured.

2. The method of claim 1, wherein extrapolating the plurality of density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured comprises extrapolating the plurality of density values to the pressure level outside of the pressure range.

3. The method of claim 1, wherein interpolating the plurality of density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured comprises interpolating the plurality of density values to the pressure level inside of the pressure range.

4. The method of claim 1, wherein measuring the plurality of density values of the fluid sample comprises:

measuring a first density value at a first pressure level within the pressure range;

altering the first pressure level to a second pressure level within the pressure range; and

measuring a second density value at the second pressure level.

5. The method of claim 4, wherein the at least one of extrapolating and interpolating the plurality of density values of the fluid sample to a pressure level different that the distinct pressure in which the density value is measured comprises at least one of extrapolating and interpolating the first density value and the second density value.

6. The method of claim 5, further comprising:

determining a third density value at a third pressure level outside of the pressure range based, at least in part, on extrapolating the first density value and the second density value.

7. The method of claim 5, further comprising:

determining a third density value at a third pressure level inside of the pressure range based, at least in part, on interpolating the first density value and the second density value.

8. The method of claim 1, wherein extrapolating the plurality of density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured comprises at least one of:

linearly extrapolating the plurality of density values to the pressure level outside the pressure range, and

logarithmically extrapolating the plurality of density values to the pressure level outside the pressure range.

9. The method of claim 1, wherein interpolating the plurality of density values of the fluid sample to the pressure level different than the distinct pressure level in which the density value is measured comprises at least one of:

linearly interpolating the plurality of density values to the pressure level inside the pressure range, and

logarithmically interpolating the plurality of density values to the pressure level inside the pressure range.

10. The method of claim 1, wherein the pressure level different that the distinct pressure comprises at least one of a formation pore pressure level, a predetermined pressure level, and an arbitrary pressure level.

11. The method of claim 1, wherein measuring the plurality of density values of the fluid sample comprises measuring, by at least one of a vibrating rod, a tuning fork and a vibrating tube, the plurality of density values of the fluid sample.

12. The method of claim 1, wherein each respective pressure level within the pressure range is determined by at least one of a crystal quartz gauge, a silicon-on-isolator gauge and a strain gauge.

13. A method of determining a density of a fluid in a formation, the method comprising:

measuring a first fluid density value of a fluid sample at a first pressure;

altering the first pressure to a second pressure different than the first pressure;

measuring a second fluid density value of the fluid sample at the second pressure; and

at least one of extrapolating and interpolating a third fluid density value at a third pressure based, at least in part, on the first fluid density value at the first pressure and the second fluid density value at the second pressure;

wherein the third pressure is different than the first pressure and the second pressure.

14. The method of claim 13, further comprising:

tuning one or more Equation-of-State model based, at least in part, on the third fluid density value.

15. The method of claim 14, further comprising:

verifying the third density value with the one or more Equation-of-State model; and

correcting the third density value based, at least in part, on a temperature of the fluid sample and a contamination of the fluid sample.

16. The method of claim 13, wherein altering the first pressure to a second pressure different than the first pressure comprises at least one of increasing the first pressure and decreasing the first pressure.

17. An apparatus for determining a density of a fluid in a formation, the apparatus comprising:

a fluid chamber adapted to at least temporarily hold a fluid sample;

one or more pressure regulator to regulate a pressure applied to the fluid sample between a first pressure and a second pressure, the first pressure being different than the second pressure;

one or more pressure gauge to measure the pressure applied to the fluid sample;

one or more density sensor to measure the density of the fluid sample at the first pressure and the second pressure; and

one or more signal processor to determine a density of the fluid sample at a third pressure via at least one of an extrapolation technique and an interpolation technique, the third pressure being different than the first pressure and the second pressure.

18. The apparatus of claim 17, wherein the fluid chamber, the one or more pressure regulator, the one or more pressure gauge and the one or more density sensor are housed in a downhole tool.

19. The apparatus of claim 17,

wherein the one or more density sensor generates density data representative of the density of the fluid sample at the first pressure and the second pressure, and stores the density data in the memory in a downhole tool; and

wherein the one or more signal processor is housed in a surface logging unit.

20. The apparatus of claim 17, wherein the one or more signal processor linearly extrapolates the density of the fluid sample at the pressure level outside of the pressure range when the fluid sample is at least one of water and oil, and logarithmically extrapolates the density of the fluid sample at the pressure level outside of the pressure range when the fluid sample is a gas.