Patent Publication Number: US-2013239671-A1

Title: Pressure-corrected density of a fluid

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&#39;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&#39;s surface (e.g., in a downhole tool) and/or on the Earth&#39;s surface. In some examples, some extrapolated and/or interpolated values (e.g., third density value) may be determined in situ under the Earth&#39;s surface and/or on the Earth&#39;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 (CO 2 ). 
     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/cm 3  to 1.061 g/cm 3 . 
       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/cm 3 . 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.