BACKGROUND

[0001] This disclosure relates generally to analysis of formation fluid and, more particularly, to formation fluid analysis apparatus and related methods.

Description of the Related Art

[0002] Formation fluid in a downhole reservoir can include a mixture of oil, water, and gas phases. The respective compositions of the oil and gas phases can depend on pressure and temperature. Analyses of fluid properties, fluid volume, and phase composition versus pressure and/or temperature provide an understanding of fluid transport in the reservoir and can be used to generate reservoir models. During a well test, downhole formation fluid samples are collected and retrieved at the surface, where pressure-volume (PV) and/or pressure-volume-temperature (PVT) analyses are performed on the fluid. However, the results of such ex situ PV and/or PVT analyses, which can include, for example, phase transition metrics such as a bubble point (gas to liquid) or dew point (liquid to gas) are not known until after the well test has been completed at the surface.

[0003] Wireless acoustic telemetry includes transmission of acoustic signals via a network of repeater nodes that wirelessly receive and send messages included in the signals. One or more acoustic repeaters can interface with downhole equipment, such as a sensor, to transmit data between the surface and the equipment in the form of acoustic wave signals that are propagated across the repeater network via a propagation medium, such as a production pipe to which the repeater is coupled. In some examples, wireless telemetry can be used to control a control valve (e.g., a tester valve, a choke) that controls production flow. In some examples, collection of the fluid samples can be selectively triggered based on acoustic commands sent from the surface to a downhole fluid sampling device (e.g., a container) via an acoustic telemetry system. The sampling device(s) include inlet(s) that can be opened to collect the fluid via activation of respective triggering mechanism(s) (e.g., a rupture disk, an electromechanical actuator). SUMMARY

[0004] Certain aspects of some embodiments disclosed herein are set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of certain forms the invention might take and that these aspects are not intended to limit the scope of the invention. Indeed, the invention may encompass a variety of aspects that may not be set forth below.

[0005] An example apparatus includes a sample platform to be disposed in a wellbore and a first chamber defined by the sample platform. The first chamber is to capture a fluid flowing in the wellbore. The example apparatus includes a second chamber coupled to the sample platform. The example apparatus includes a first sensor coupled to the sample platform and a controller. The sample platform, the second chamber, and the first sensor are to be communicatively coupled to the controller. The controller is to selectively instruct the second chamber to one of depressurize or pressurize the fluid, the first sensor to generate fluid data for the fluid during the depressurization or the pressurization of the fluid and conduct a pressure- volume analysis for the fluid based on the fluid data.

[0006] An example apparatus includes a housing having a first end and a second end, the first end and the second end to be aligned with a flow path of fluid in a wellbore. The example apparatus includes a first chamber defined by the housing. The first chamber is to collect the fluid. The example apparatus includes a second chamber coupled to the housing and means for selectively depressurizing or pressurizing the fluid via the second chamber.

[0007] An example method includes directing, by executing an instruction with a processor, a sample platform to capture fluid flowing in a wellbore. The example method includes directing, by executing an instruction with a processor, a sample container coupled to the sample platform to depressurize the fluid captured by the sample platform. The example method includes accessing, by executing an instruction with a processor, fluid property data for the depressurized fluid. The example method includes directing, by executing an instruction with a processor, the sample platform to release the fluid. [0008] Various refinements of the features noted above may exist in relation to various aspects of the present embodiments. Further features may also be incorporated in these various aspects. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. Again, the brief summary presented above is intended to familiarize the reader with certain aspects and contexts of some embodiments without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] FIG. 1 illustrates an example formation fluid analyzer system constructed in accordance with the teachings disclosed herein.

[0010] FIG. 2 illustrates a first example sample platform that may be implemented with the example system of FIG. 1.

[0011] FIG. 3 illustrates a second example sample platform that may be implemented with the example system of FIG. 1.

[0012] FIG. 4 illustrates a first example sample container that may be used with the example sample platforms of FIGS. 1-3.

[0013] FIG. 5 illustrates a second example sample container that may be used with the example sample platforms of FIGS. 1-3.

[0014] FIG. 6 illustrates a third example sample container that may be used with the example sample platforms of FIGS. 1-3.

[0015] FIG. 7 illustrates an example optical probe associated with a first example phase nucleation device that may be used with the example sample platforms of FIGS. 1-3.

[0016] FIG. 8 illustrates an example optical probe associated with a second example phase nucleation device that may be used with the example sample platforms of FIGS. 1-3. [0017] FIG. 9 is a block diagram of an example fluid analyzer that may be used to implement the example system of FIG. 1.

[0018] FIG. 10 is a first example phase diagram that may be generated by the example system of FIG. 1.

[0019] FIG. 1 1 is a second example phase diagram that may be generated by the example system of FIG. 1.

[0020] FIG. 12 is a third example phase diagram that may be generated by the example system of FIG. 1.

[0021] FIG. 13 is a flow diagram of an example method that may be executed to implement the example system of FIG. 1.

[0022] FIG. 14 illustrates an example downhole tool control system 1400 constructed in accordance with the teachings disclosed herein.

[0023] FIG. 15 is a flow diagram of an example method that may be executed to implement the example system of FIG. 14.

[0024] FIG. 16 is a diagram of a processor platform that may be used to carry out the example method of FIG. 13 and/or, more generally, to implement the example system of FIG. 1 .

[0025] FIG. 17 is a diagram of a processor platform that may be used to carry out the example method of FIG. 15 and/or, more generally, to implement the example system of FIG. 14.

[0026] The figures are not to scale. Wherever possible, the same reference numbers will be used throughout the drawing(s) and accompanying written description to refer to the same or like parts.

DETAILED DESCRIPTION

[0027] 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 for purposes of explanation and to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. [0028] When introducing elements of various embodiments, the articles“a,”“an,” “the,” and“said” are intended to mean that there are one or more of the elements. The terms“comprising,”“including,” and“having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, any use of any of the terms“top,”“bottom,”“above,”“below,” other directional terms, and variations of these terms is made for convenience, but does not mandate any particular orientation of the components.

[0029] Fluid produced by a downhole formation can include a mixture of oil, water, and gas. The oil and gas phases can include a mixture of hydrocarbons and, in some examples, compounds such as carbon dioxide, hydrogen sulfide, organo-sulfur compounds, etc. The oil and gas phases are miscible and the respective compositions of the oil and gas phases can depend on pressure and/or temperature.

[0030] A well test can be performed to obtain data that enables the formation fluid to be characterized with respect to the behavior of the formation fluid (e.g., phase transitions) as the fluid travels from the reservoir through pipelines to the surface. Results of the well test can be used to evaluate a state of the well, assess the ability of the reservoir to produce hydrocarbons, and to identify the phase behavior of the hydrocarbons. In some examples, fluid samples are collected during a well test and analyzed at the surface to determine fluid behavior (e.g., phase transitions) with respect to pressure, volume, and/or temperature or, put another way, fluid PVT (pressure-volume-temperature) properties. However, in such examples, the fluid PVT properties are not known until after the well test has been completed at the surface. Thus, fluid samples are collected and analyzed ex situ without an understanding of the downhole conditions in which fluid is flowing and the response of the fluid to the conditions. Further, an understanding of characteristics of the formation is delayed until the PVT analyses are complete at the surface.

[0031] Example apparatus, systems, and methods disclosed herein provide for PV and/or PVT analyses to be performed on sample fluid downhole (e.g., in situ, during a well test). In some disclosed examples, sample fluid is collected in a fluid sample platform including a chamber having a fixed volume. The sample platform can be aligned with (e.g., disposed in line with) production tubing to capture the fluid under downhole flow conditions. For example, the sample platform can be coupled between two portions of the production tubing and, thus, integrated into a fluid flow path such that fluid flowing in the production tubing flows through the sample platform. Example fluid sample platforms disclosed herein include means for selectively enabling the sample fluid to be depressurized (e.g., by expanding volume at the sample platform). In some examples, the volume changing means includes a sampling device (e.g., a sample container) including a piston to enable fluid to enter a sample chamber of the sampling device. Sensors disposed at the sample platform can measure fluid pressure, downhole temperature, and/or collect data about fluid properties such as bubble formation, density, phase composition, viscosity, etc. during, for example, the depressurization of the fluid. In some examples, the data collected by the sensors is analyzed with respect fluid phase behavior to detect the formation of liquid, solid, or gas. Bubble points or dew points can be determined based on the sensor data and used to generate, for example, fluid phase diagrams to characterize the sample fluid at different pressures and/or temperatures. In some disclosed examples, the piston of the sampling device selectively pressurizes the sample fluid to provide for multiple measurement cycles and to enable analysis of the fluid behavior over the cycles. In collecting and analyzing the fluid in the downhole environment, examples disclosed herein substantially reduce and/or prevent discrepancies in the data analysis that can arise when the fluid is analyzed at the surface (e.g., due to pressure changes) as well as risks for contamination of the fluid.

[0032] In some disclosed examples, the sample platform is controlled via wireless acoustic telemetry with respect to collection of the sample, transmission of the sensor data to a downhole controller and/or the surface, etc. The sensor data can be used to perform a PVT analysis in substantially real-time by a downhole controller and/or a surface controller to determine for, example, changes in fluid properties with respect to pressure, temperature, and/or volume. In some examples, the results of the PVT analysis are used to generate a reservoir model. The results of the PVT analysis can also be used estimate fluid compressibility versus pressure and temperature. In some examples, parameters of the well test can be adjusted or optimized based on the PVT analysis. [0033] In some disclosed examples, the sampling device(s) include a compressible fluid such as a gas disposed in a chamber of the sampling device(s). Some such disclosed examples include a sensor to measure changes in the pressure of the compressible gas during movement of the piston (e.g., during depressurization of the fluid). In some examples, the pressure data for the compressible fluid can be analyzed to determine, for example, a volume of sample fluid being collected by the sampling device(s) over time. In other examples, the pressure data can be analyzed to determine a position of the piston and used to control a downhole tool.

[0034] In some disclosed examples, the movement of the piston is monitored to determine the volume of the sample chamber during the depressurization of the fluid.

[0100] FIG. 1 illustrates an example formation fluid analyzer system 100. The example system 100 includes production tubing 102 disposed in a wellbore 104. The example system 100 includes one or more sample platforms 106 coupled to the production tubing 102. In some examples, the sample platforms 106 are coupled to (e.g., mounted to) the production tubing 102 such that the sample platforms 106 are aligned with the production tubing 102 (e.g., along a longitudinal axis extending through the production tubing 102), as illustrated in FIG. 1.

[0101] In the example of FIG. 1 , the sample platforms 106 selectively collect fluid (e.g., formation fluid) flowing through the production tubing 102. The sample platforms 106 include respective inlet valves 108 and outlet valves 1 10 disposed at the respective ends of each sample platform 106. In operation, the inlet valves and the outlet valves 108, 1 10 control flow of fluid in the production tubing 102. In the example of FIG. 1 , the inlet valves 108 control the flow of fluid into the sample platforms 106 and the outlet valves 1 10 control the flow of fluid out of the sample platforms 106 toward the surface.

[0102] The example sample platforms 106 include one or more sensors 109. As disclosed herein, the sensor(s) 109 collect data about one or more properties of the fluid collected by the sample platforms 106 such as density, viscosity, composition, etc. The sensor(s) 109 can also measure fluid pressure overtime. In some examples, the sensor(s) 109 measure temperature of the downhole environment (e.g., an interior of the chamber).

[0103] The example system 100 of FIG. 1 includes a bi-directional telemetry system 1 11 that provides for communication between a processor 1 12 disposed outside the wellbore 104 at the surface and one or more tools disposed in the wellbore 104, such as the valves 108, 1 10 and/or sensor(s) 109 of sample platform(s) 106. The telemetry system 1 1 1 can include wireless acoustic telemetry, electromagnetic telemetry, or annulus pressure telemetry. In other examples, the telemetry system 1 11 is wireline. In some examples, the telemetry system 11 1 communicates with two or more surface processors.

[0104] In the example of FIG. 1 , the valves 108, 1 10 of the respective sample platforms 106 are communicatively coupled to a tool bus 114, as represented by arrows 1 16 in FIG. 1. The tool bus 1 14 is communicatively coupled to the telemetry system 1 11 via a downhole tool controller 118 (e.g., a processor). Although the example of FIG. 1 includes one tool controller 1 18, the example system 100 can include additional tool controllers 1 18 disposed downhole in the wellbore 104. For example, each tool controller 1 18 can be communicatively coupled to one or more sample platforms 106 via the tool bus 1 14.

[0105] In the example of FIG. 1 , one or more instructions can be delivered from the surface processor 1 12 to the valves 108, 110 of the sample platform(s) 106 via the telemetry system 1 11 , the tool controller 1 18, and the tool bus 1 14. The instructions can include, for example, instructions for the valves 108, 1 10 to open or close to control the flow of fluid into or out of the sample platform(s) 106.

[0106] In other examples, the instruction(s) for the valves 108, 1 10 of the sample platform(s) 106 are generated by the tool controller 1 18 and delivered by the tool controller 1 18 via the tool bus 1 14. The example tool controller 1 18 includes a fluid analyzer 120. As disclosed herein, the fluid analyzer 120 can generate one or more instructions to control the valves 108, 1 10 downhole. The fluid analyzer 120 can generate the instructions based on one or more commands received from the surface (e.g., via the surface processor 1 12 and the telemetry system 1 1 1 of FIG. 1 ), another downhole device (e.g., another downhole controller), and/or based on analyses performed by the fluid analyzer 120.

[0107] In the example of FIG. 1 , the sensor(s) 109 are communicatively coupled to the tool bus 1 14, as represented by arrow 122 in FIG. 1. The sensor(s) 109 are communicatively to the downhole tool controller 1 18 and the surface processor 1 12 via the tool bus 1 14 and the telemetry system 1 1 1. In the example of FIG. 1 , data collected by the sensor(s) 109 is transmitted from the sensor(s) 109 to the tool controller 1 18 and/or the surface processor 1 12 via the tool bus 1 14 and the telemetry system 1 1 1.

[0108] In some examples, the data generated by the sensor(s) 109 is analyzed by the fluid analyzer 120 of the downhole tool controller 1 18. The fluid analyzer 120 can perform one or more operations on the data generated by the sensor(s) 109 such as filtering the raw signal data, removing noise from the raw signal data, converting the signal data from analog to digital data, and/or analyzing the data. In some examples, the fluid analyzer 120 of the tool controller 1 18 processes the data in substantially real-time as the data is received from the sensor(s) 109. In some examples, the fluid analyzer 120 transmits the processed data to the surface processor 1 12 via the telemetry system 1 1 1. The surface processor 1 12 can perform pressure-volume (PV) or pressure-volume-temperature (PVT) analyses based on the sensor data.

[0109] In other examples, the fluid analyzer 120 of the downhole tool controller 1 18 performs the PV or PVT analyses downhole based on one or more algorithms implemented by the fluid analyzer 120 and the sensor data. For example, the fluid analyzer 120 can implement the algorithm(s) based on data generated by the sensor(s) 109 (e.g., fluid pressure, time, etc.). As disclosed herein, the fluid analyzer 120 can send the results of the PV or PVT analyses to the surface processor 1 12 and/or automatically generate one or more instructions downhole based on the analyses.

[0110] FIG. 2 is a first example sample platform 200) that may be implemented with the example formation fluid analyzer system 100 of FIG. 1 (e.g., the sample platform 106 of FIG. 1 ). In the example of FIG. 2, the sample platform 200 of FIG. 2 is coupled to the production tubing 102 to enable fluid to flow from a downhole formation to the surface and to provide for in situ collection and analysis of the fluid.

[0111] The sample platform 200 of FIG. 2 includes a housing 202 that defines a chamber 203. The housing 202 hydraulically isolates a volume of the chamber 203 from the well annulus when the sample platform 200 is disposed in the wellbore 104 of FIG. 1 . A first valve 204 is disposed at a first end 206 of the housing 202. A second valve 208 is disposed at a second end 209 of the housing 202 opposite the first end 206. The second valve 208 controls a flow of fluid into the chamber 203 from the formation via the production tubing. The first valve 204 controls a flow of fluid out of the chamber 203 to the surface via the production tubing 102. The first and second valves 204, 208 are communicatively coupled to the tool bus 114 of FIG. 1 and, thus, the tool controller 1 18, as represented by arrows 21 1 in FIG. 2. The tool controller 1 18 can generate and/or transmit (e.g., from the surface processor 1 12 of FIG. 1 ) instruction(s) to control the opening and closing of the valves 204, 208. When the first valve 204 and the second valve 204 are closed, a fixed volume of sample fluid 210 is captured in the chamber 203.

[0112] The example sample platform 200 of FIG. 2 includes one or more volume changers 212 coupled to the chamber 203. As disclosed herein, the volume changer(s) 212 can include fluid sampling devices coupled to the chamber 203 (e.g., via a fluid channel). The example sample platform 200 can include additional orfewer volume changers 212 than illustrated in FIG. 2.

[0113] The volume changer(s) 212 selectively depressurize or pressurize the sample fluid 210 disposed in the sample platform 200. As disclosed herein, the volume changer(s) 212 include respective volume change drivers 214 that selectively depressurize the sample fluid 210 or pressurize the sample fluid 210 to enable the sample fluid 210 to flow into or out of the volume changer(s) 212, thereby changing a volume of the sample fluid relative to chamber 203 of the sample platform 200. The volume change drivers 214 can include, for example, pistons and/or valves. In the example of FIG. 2, the volume change drivers 214 are controlled by the fluid analyzer 120 of the tool controller 118, as represented by the arrow 215 in FIG. 2. [0114] The example sample platform 200 of FIG. 2 includes a plurality of sensors to measure one or more fluid properties, fluid pressure, volume, etc. For example, the sample platform of FIG. 2 includes a pressure sensor 216 to measure a pressure of the sample fluid disposed in the chamber 203 (e.g., during depressurization of the sample fluid). The sample platform 200 of FIG. 2 can include additional pressure sensors 216. The pressure sensor(s) 216 can be disposed in the chamber 203 of the sample platform 200 or the volume changer(s) 212.

[0115] The example sample platform 200 of FIG. 2 includes one or more fluid property sensors 217. As illustrated in FIG. 2, the fluid property sensor(s) 217 are disposed in the chamber 203 of the sample platform 200. In some examples, the fluid property sensor(s) 217 are disposed in the volume changer(s) 212. The fluid property sensor(s) 217 can measure one or properties of the sample fluid 210 such as temperature, density, viscosity, compositions, etc. In some examples, the fluid property sensor(s) 217 detect the formation of gas bubbles, liquid droplets, or solid particles in the sample fluid 210. In some examples, the fluid property sensor(s) 217 include one or more detectors or probes, such as a gas bubble detector, an optical probe, a fluid electrical resistivity probe, a fluid electrical permittivity probe, a fluid acoustic velocity probe, a fluid density probe, an optical density probe, a fluid viscosity probe, a fluid NMR (nuclear magnetic resonance) probe, etc.

[0116] In the example of FIG. 2, the volume changer(s) 212 includes volume changer sensor(s) 218 to monitor, for example, change in volume of the sample fluid as a result of activation of the volume changer(s) 212. The volume changer sensor(s) 218 can include, for example pressure sensor(s) and/or temperature sensor(s) that are used to estimate a volume of sample fluid in the volume changer(s) 212 over time, as disclosed herein. In other examples, the volume changer sensor(s) 218 generate volume data based on known fluid capacities of the volume changer(s) 212.

[0117] In the example of FIG. 2, each of the sensor(s) 216, 217, 218 of the example sample platform 200 of FIG. 2 is communicatively coupled a tool bus (e.g., the tool bus 1 14 of FIG. 1 ), as represented by arrows 220 in FIG. 2. As disclosed in FIGS. 1 and 2, the tool bus 1 14 is communicatively coupled to the tool controller 1 18. Data generated by the sensor(s) 216, 217, 218 is transmitted to the tool controller 118 via the tool bus 1 14. In some examples, the data generated by the sensor(s) 216, 217, 218 is transmitted to the surface processor 1 12 via the telemetry system 1 11 of FIG. 1.

[0118] In some examples, the sample platform 200 of FIG. 2 includes one or more phase nucleation devices 222. The phase nucleation device(s) 222 facilitate phase transitions of the sample fluid 210 (e.g., from liquid to gas during depressurization of the sample fluid). As disclosed herein, the phase nucleation device(s) 222 include a perturbation generator to facilitate the phase transition via heat or mechanical agitation based on the type of fluid involved in the transition. In the example of FIG. 2, the phase nucleation device(s) 222 are disposed in the chamber 203 for contact with the sample fluid 210. In some example, the phase nucleation devices 222 are disposed in the volume changer(s) 212. In the example of FIG. 2, the phase nucleation device(s) 222 are communicatively coupled to the tool controller 1 18 via the tool bus 1 14, as represented by arrows 224 in FIG. 2. In some examples, one or more of the fluid property sensor(s) 216 are associated with the phase nucleation device(s) 222.

[0119] In some examples, the fluid analyzer 120 of the tool controller 1 18 generates one or more instructions with respect to the positions of the first and/or second valves 204, 208 to control the flow of fluid into and out of the sample platform 200. In some examples, the fluid analyzer 120 generates one or more instructions for the volume change driver(s) 214 of the volume changer(s) 212 to depressurize or pressurize the sample fluid 210 (e.g., via movement of piston(s) of the volume changer(s) 212). Also, in some examples, the fluid analyzer 120 generates one or more instructions with respect to operation of the phase nucleation device(s) 222. In the example of FIG. 2, the instructions generated by the fluid analyzer 120 are based on one or more predefined algorithms implemented by the fluid analyzer 120 and/or the data generated by the sensor(s) 216, 217, 218. As disclosed herein, the fluid analyzer 120 can conduct PV and/or PVT analyses based on the data generated by the sensor(s) 216, 217, 218 for the fluid collected by the sample platform 200 of FIG. 2. [0120] FIG. 3 illustrates a second example sample platform 300 (e.g., the sample platform 106 of FIG. 1) that may be implemented with the example system 100 of FIG. 1. As compared to the first example sample platform 200 of FIG. 2, in which the volume changers 212 disposed outside the chamber 203, the example sample platform 300 of FIG. 3 includes volume changers disposed in a chamber of the sample platform 300.

[0121] The example sample platform 300 of FIG. 3 includes a sample carrier 302 coupled to the production tubing 102. The sample carrier 302 includes a housing 304 defining a chamber 305. The housing 304 hydraulically isolates a volume of the chamber 305 from the well annulus when the sample platform 300 is disposed in the wellbore 104 of FIG. 1. A first valve 306 (e.g., a control valve such as a tester valve (e.g., an electro-hydraulic test valve, a mechanical test valve), a choke, a sliding sleeve) is disposed at a first end 307 of the housing 304 of the sample carrier 302. A second valve 308 (e.g., a control valve) is disposed at a second end 310 of the housing 304 of the sample carrier 302. The valves 306, 308 control the flow of fluid through the production tubing 102 and the sample carrier 302 from a formation to the surface (e.g., by shutting off the flow path or opening the flow path). The valves 306, 308 are communicatively coupled to the tool controller 1 18 via the tool bus 1 14, as represented by arrows 313 of FIG. 3. The tool controller 1 18 controls the opening and closing of the valves 306, 308 based on one or more instructions generated by the fluid analyzer 120 of the tool controller 1 18 and/or the surface processor 1 12 of FIG. 1. When the first and second valves 306, 308 are closed, a fixed volume of sample fluid can be captured by the sample platform 300 of FIG. 3.

[0122] In the example of FIG. 3, one or more sample containers 312 are disposed in the chamber 305 of the sample carrier 302. The sample carriers 302 are disposed relative to the flow of fluid though the production tubing 102 via the sample carrier 302. In the example of FIG. 3, the sample container(s) 312 serve as volume changers to depressurize or pressurize the fluid collected by the sample carrier 302.

[0123] Each of the sample containers 312 includes a trigger 314. The trigger 314 is selectively controlled to open or close the sample container(s) 312 and, thus, enable the sample container(s) 312 to collect sample fluid. The trigger(s) 314 can include, for example, a rupture disk or an electromechanical actuator. The sample container(s) 312 can be selectively activated to collect fluid based on one or more instructions generated by the fluid analyzer 120 of the downhole tool controller 1 18 and/or the surface processor 1 12 of FIG. 1. In some examples, two or more sample containers 312 are selectively opened based on a predefined sequence.

[0124] The example sample platform 300 of FIG. 3 includes one or more pressure sensors or pressure gauges 316. In the example of FIG. 3, the pressure gauge(s) 316 are disposed in the chamber 305 of the sample carrier 302. In other examples, the pressure gauge(s) 316 are disposed in the sample container(s) 312. The pressure gauge(s) 316 are communicatively coupled to the tool controller 1 18 via the tool bus 1 14, as illustrated by the arrow 317 of FIG. 3. The pressure gauge(s) 316 measure fluid pressure during, for example, the depressurization of the fluid when the sample container(s) or volume changer(s) 312 are activated. The pressure gauge(s) 316 transmit the fluid pressure data to the fluid analyzer 120 of the tool controller 1 18.

[0125] The example sample platform 300 of FIG. 3 includes one or more other fluid property sensor(s) 318. The sensors(s) 318 can be disposed in the chamber 305 of the sample carrier 302. In some examples, the sensor(s) 318 are disposed in the sample container(s) 312.

[0126] In the example of FIG. 3, the fluid property sensor(s) 318 include probe(s). The probe(s) can include, for example, optical probe(s) that can be used to detect bubbles in the sample fluid. The probe(s) of FIG. 3 are associated with phase nucleation device(s) 320 that facilitate, for example, the formation of bubbles via heating or agitation. The sensor(s) 318 (e.g., the probe(s)) and/or the phase nucleation device(s) 320 are communicatively coupled to the tool controller 1 18 via the tool bus 1 14, as illustrated by arrows 321 , 323 of FIG. 3. The example sample carrier 302 and/or the sample container(s) 312 can include additional sensor(s) 318 and/or phase nucleation device(s) 320 than shown in FIG. 3.

[0127] In the example of FIG. 3, the fluid analyzer 120 of the tool controller 1 18 can generate one or more instructions to control the valves 306, 308, the trigger(s) 314, the sensor(s) 316, 318, and/or the phase nucleation device(s) 320 based on commands received from the surface processor 1 12 of FIG. 1 during, for example, a well test. In some examples, the fluid analyzer 120 automatically generates the instructions based on one or more algorithms implemented by the fluid analyzer 120, as disclosed herein.

[0128] In the example of FIG. 3, the sample container(s) 312 serve as volume changers with respect to the sample fluid collected by the sample carrier 302. For example, the sample container(s) 312 enable the sample fluid in the chamber 305 of the sample carrier 302 to flow into the sample container(s) 312, thereby changing a volume of the sample fluid relative to the chamber 305.

[0129] FIG. 4 illustrates an example sampling device or sample container 400 that may be implemented with the sample platform 200 of FIG. 2 (e.g., as a volume changer 212) and/or the example sample platform 300 of FIG. 3 (e.g., as a sample container or volume changer 312). Although the example sample container 400 is discussed herein substantially in connection with the example sample platform 300 of FIG. 3, the sample container 400 can be implemented with the example sample platforms 106, 200 of FIGS. 1 and 2.

[0130] The example sample container 400 of FIG. 4 is communicatively coupled to one or more tool controllers 401 (e.g., the tool controller 1 18 of FIG. 1 , a dedicated tool controller, etc.). The example sample container 400 of FIG. 4 includes a sample chamber 402 and a dump chamber 404 defined by a housing 405 of the sample container 400.

[0131] The example sample container 400 includes an inlet 406 disposed proximate to the sample chamber 402 such that fluid entering the inlet 406 flows into the sample chamber 402. The inlet 406 includes an inlet valve 408 to control the flow of fluid through the inlet 406. In the example of FIG. 4, opening and closing of the inlet valve 408 is controlled by a trigger 409 (e.g., the trigger 314 of FIG. 2). The trigger 409 is communicatively coupled to the tool controller(s) 401. The trigger 409 can include, for example, an electromechanical actuator.

[0132] The example sample container 400 includes a piston 410 (e.g., a volume changer driver) disposed in the sample chamber 402. The piston 410 (e.g., a floating piston) defines two volumes in the sample chamber 402, namely, a sample volume portion 412 and a hydraulic fluid volume portion 414. The example sample container 400 includes an orifice or flow restrictor 416 that couples the hydraulic fluid volume portion 414 to the dump chamber 404. In some examples, a flow control valve 418 is disposed at the orifice 416. The flow control valve 418 can be controlled by the example tool controller 401 .

[0133] Before the sample container 400 of FIG. 4 is disposed downhole, the sample chamber 402 is primed with a hydraulic fluid 420 (e.g., hydraulic oil). Also, the piston 410 is disposed proximate to (e.g., pushed toward) the inlet 406. The dump chamber includes gas 421.

[0134] The example sample container 400 of FIG. 4 can be disposed in, for example, the chamber 305 of the sample carrier 302 of FIG. 3 such that the sample container 400 can collect sample fluid captured by the sample carrier 302 via the production tubing 102. When the example sample container 400 is disposed in the sample carrier 302 of FIG. 3, a decision may be made (e.g., by the fluid analyzer 120 of the tool controller 1 18 and/or the surface processor 1 12 of FIG. 1 ) to depressurize the sample fluid collected by the sample carrier 302.

[0135] In such examples, the sample container 400 is activated to enable fluid to flow into the sample container 400. The tool controller(s) 401 instruct the trigger 409 to open the inlet valve 408 via (e.g., wireless) communication between the tool controller(s) 401 and the sample container 400 to enable sample fluid 422 to flow into the sample volume portion 412 of the sample chamber 402. Also, the flow control valve 418 of the orifice 416 is opened based on, for example, an instruction from the tool controller 401. The entry of the sample fluid 422 into the sample volume portion 412 of the sample chamber 402 causes the piston 410 to push the hydraulic fluid 420 from the hydraulic fluid volume portion 414 into the dump chamber 404 via the orifice 416. As the hydraulic fluid 420 moves from the hydraulic fluid volume portion 414 into the dump chamber 404, the hydraulic fluid 420 moves from an area of high pressure to an area of low pressure. The flow control valve 418 can provide for a variable opening to control a flow rate of the hydraulic fluid 420. [0136] In the example of FIG. 4, as the piston 410 pushes the hydraulic fluid 420 from the hydraulic fluid volume portion 414 into the dump chamber 404, the volume of the sample fluid 422 that can be received in the sample volume portion 412 of the sample container 400 increases. Thus, the example sample container 400 of FIG. 4 serves as a volume changer. Also, the orifice 416 controls a flow rate of the hydraulic fluid 420. Therefore, the sample container 400 of FIG. 4 provides for a controlled depressurization or low-shock sampling of the sample fluid 422 during the volume expansion that provides for thermal equilibrium during the depressurization. The low- shock sampling provided by the sample container 400 helps to prevent the sample fluid 422 from reaching the bubble point pressure, which could induce a two-phase condition (e.g., liquid and gas) into the sample chamber 402.

[0137] In some examples, the sample container 400 can be used to create one or more measurement cycles or PV cycles in which the sample fluid collected by the sample carrier 302 is depressurized by the sample container 400 and pressurized by removal of the sample fluid from the sample container 400. For example, the sample container 400 can include one or more means for releasing the fluid from the sample volume portion 412 of the sample chamber 402. The means for releasing the fluid can include, for example, a hydraulic pump to draw the hydraulic fluid from the dump chamber 404 to the hydraulic fluid volume portion 414, thereby causing the piston 410 to push the sample fluid out of the sample volume portion 412 (e.g., and into the carrier 302 of FIG. 3). Additional sample fluid can be collected in the sample container 400 after the sample fluid is released as part of repeated cycles of depressurizing and pressurizing the sample fluid to collect multiple measurements, verify the measurements collected during each cycle, etc. In some examples the sample fluid can be pressurized to reservoir pressure or higher (e.g., after depressurization) based on annulus pressure.

[0138] The sample container(s) 312 disposed in the sample carrier 302 of FIG. 3 can have other designs than the example sample container 400 of FIG. 4. For example, the sample container can include a sample chamber, piston, and a linaer actuator to control movement of the piston to collect sample fluid in the sample chamber or release sample fluid from the sample chamber. As another example, the sample container can include a sample chamber, an inlet coupled to the sample chamber, and an outlet coupled to the sample chamber opposite the inlet. In such examples, the inlet and outlet can include respective valves to selectively collect sample fluid in the sample chamber or release sample fluid from the sample chamber as part of repeated cycles of sample fluid depressurization and pressurization.

[0139] In some examples, a volume of the sample fluid in the sample volume portion 412 of the sample container 400 of FIG. 4 is known when the sample volume portion 412 is fully or substantially full, i.e. , when the piston 410 has moved a maximum allowable distance away from the inlet 406 of the sample container 400. However, the volume of fluid in the sample volume portion 412 of the sample container 400 at any given time during movement of the piston 410 is not known. Thus, an amount by which the sample fluid volume has been expanded relative to the sample platform(s) 106, 200, 300 is not known. In some examples of the formation fluid analyzer system 100 of FIGS. 1-3, the volume changer(s) 212, 312 provide for monitoring of a volume of sample fluid collected by the volume changer(s) 212, 312 over time. The monitoring of the change in volume during depressurization or pressurization of the sample fluid can be used to determine fluid behavior at different volumes and pressures.

[0140] FIG. 5 illustrates a first example sampling device or sample container 500 that provides for monitoring of a volume of sample fluid in a sample chamber of the sample container 500 over time. The sample container 500 of FIG. 5 may be implemented with, for example, the sample platform 300 of FIG. 3 (e.g., a sample container 312) to serve as a volume changer. The example sample container 500 of FIG. 5 can be disposed in, for example, the chamber 305 of the sample carrier 302 of FIG. 3 such that the sample container 500 can collect sample fluid collected by the sample carrier 302 via the production tubing 102. Although the example sample container 500 is discussed in connection with the example sample platform 300 of FIG. 3, the sample container 500 can be implemented with the example sample platforms 106, 200 of FIGS. 1 and 2. [0141] The example sampling container 500 of FIG. 5 is communicatively coupled to one or more tool controllers 501 (e.g., the tool controller 1 18 of FIG. 1 , a dedicated tool controller, etc.). The example sample container 500 of FIG. 5 includes a sample chamber 502 and a dump chamber 504 defined by a housing 505 of the sample container 500. The example sample container 500 includes an inlet 506 disposed proximate to the sample chamber 502 such that fluid entering the inlet 506 flows into the sample chamber 502. The inlet 506 includes an inlet valve 508 to control the flow of fluid through the inlet 506. In the example of FIG. 5, opening and closing of the inlet valve 508 is controlled by a trigger 509 (e.g., the trigger 314 of FIG. 2). The trigger 509 is communicatively coupled to the tool controller(s) 501 . The trigger 509 can include, for example, an electromechanical actuator.

[0142] The example sample container 500 of FIG. 5 includes a piston 510 (e.g., a volume change driver) disposed in the sample chamber 502. The piston 510 (e.g., a floating piston) defines two volumes in the sample chamber 502, namely, a sample volume portion 512 and a hydraulic fluid volume portion 514. The example sample container 500 includes an orifice or flow restrictor 516 that couples the hydraulic fluid volume portion 514 to the dump chamber 504. A flow control valve 518 is disposed at the orifice 516. The flow control valve can be controlled by the example tool controller 501.

[0143] Before the sample container 500 of FIG. 5 is disposed downhole, the sample chamber 502 is primed with a hydraulic fluid 520 (e.g., hydraulic oil). Also, the piston 510 is disposed proximate to (e.g., pushed toward) the inlet 506. The dump chamber 504 includes a compressible fluid such as gas 521. In the example of FIG. 5, the gas 521 in the dump chamber 504 is at a lower pressure (e.g., atmospheric pressure) relative to a pressure of the hydraulic fluid 520 in the sample chamber 502.

[0144] The example sample container 500 of FIG. 5 can be disposed in, for example, the chamber 305 of the sample carrier 302 of FIG. 3 such that the sample container 500 can collect sample fluid captured by the sample carrier 302 via the production tubing 102. When the example sample container 500 is disposed in the sample carrier 302 of FIG. 3, a decision may be made (e.g., by the fluid analyzer 120 of the tool controller 1 18 and/or the surface processor 1 12 of FIG. 1 ) to depressurize the sample fluid collected by the sample carrier 302.

[0145] In such examples, the sample container 500 is activated to enable fluid to flow into the sample container 500. The tool controller(s) 501 instruct the trigger 509 to open the inlet valve 508 via (e.g., wireless) communication between the tool controller(s) 501 and the sample container 500 to enable sample fluid 522 to flow into the sample volume portion 512 of the sample chamber 502. Also, the flow control valve 518 of the orifice 516 is opened based on instruction(s) from the tool controller(s) 501. The entry of the sample fluid 522 into the sample volume portion 512 of the sample chamber 502 causes the piston 510 to push the hydraulic fluid 520 from the hydraulic fluid volume portion 514 into the dump chamber 504 via the orifice 516. As the hydraulic fluid 520 moves from the hydraulic fluid volume portion 514 into the dump chamber 504, the hydraulic fluid 520 moves from an area of high pressure to an area low pressure. The flow control valve 518 can provide for a variable opening to control a flow rate of the hydraulic fluid 520.

[0146] In the example of FIG. 5, as the piston 510 pushes the hydraulic fluid 520 from the hydraulic fluid volume portion 514 into the dump chamber 504, the volume of the sample fluid 522 that can be received in the sample volume portion 512 increases. The orifice 516 controls a flow rate of the hydraulic fluid 520. Thus, the example sample container 500 of FIG. 5 serves as a volume changer that provides for low-shock sampling of the sample fluid 522.

[0147] The example sample container 500 of FIG. 5 also includes one or more sensors 524 disposed in the dump chamber 504. In the example of FIG. 5, the sensor(s) 524 include a pressure gauge to measure a pressure of the gas 521 in the dump chamber 504 over time and temperature sensor to measure as temperature of the gas 521 in the dump chamber 504 over time. The sensors 524 are communicatively coupled to the tool controller(s) 501 to transmit temperature data. In the example of FIG. 5, the pressure data can be used to estimate a volume of the sample fluid 522 collected in the sample chamber 502 overtime. The example sample container 500 can include additional sensors 524 to those illustrated in FIG. 5, including sensors 524 disposed elsewhere in the sample container 500 (e.g., the sample chamber 502).

[0148] As illustrated in FIG. 5, the sample chamber 502, the sample volume portion

512, the hydraulic fluid volume portion 514, and the dump chamber 504 define particular volumes. For example, before sampling the sample fluid 522, a volume V _s of the sample chamber 502 can be defined as:

[0149] 1/s = Von, where Von refers to a volume of hydraulic fluid 520 (e.g., hydraulic oil) in the sample chamber 502 (Equation 1 ).

[0150] Also, before sampling is triggered, a volume VD of the dump chamber 504 can be defined as:

[0151] VD = refers to a volume of gas 521 in the dump chamber 504 and where the gas can be characterized by an equation of state f(P, V, T) (Equation 2).

[0152] During sampling, the sample volume portion 512 defines a volume Vsampie and the hydraulic fluid volume portion 514 defines a volume V ₀ n/sampie. Thus, during sampling, a volume of the sample chamber 502 can be defined as:

[0153] Vs ⁼ Vsampie ⁺ Von/sampie (Equation 3).

[0154] Also, as sample fluid 522 moves into the sample volume portion 512, the dump chamber 504 fills with hydraulic fluid 520. Thus, the dump chamber 504 includes a volume of gas l/ _gas and a volume of hydraulic fluid Von/Dump. During sampling, a volume of the dump chamber 504 can be defined as:

[0155] V _D = V _G as + Von/Dump (Equation 4).

[0156] Thus, during sampling, the volumes VG _BS and Von/sampie decrease while the volumes Vsampie and Von/Dump increase.

[0157] In the example sample container 500 of FIG. 5, pressure P _Gas of the gas in the dump chamber 504 can be monitored by the pressure gauge 524. Also, the temperature Teas of the gas in the dump chamber 504 can be monitored by the sensor 524. Based on the pressure data and the temperature data, the tool controller^) 501 and/or the fluid analyzer 120 of the tool controller 1 18 of FIGS. 1-3 can determine a volume of the sample fluid captured by the sample container 500 of FIG. 5 over time.

[0158] For example, for a gas at a low pressure (e.g., the gas 521 in the dump chamber 504), the equation of state f (PGas, Teas, VG _BS ) can be approximated by the following ideal gas law:

[0159] PGas* VGas = riGas*R* TGas , where riGas is a quantity of gas 521 n the dump chamber 504 and R is an ideal gas constant (Equation 5).

[0160] The volume VGas of the gas in the dump chamber 504 can be determined by measuring pressure P _GSS (e.g., using the pressure gauge 524) and temperature TGBS (e.g., using the temperature sensor 524) as follows:

[0161] V _Gas ⁼ (/7 _G *R*7 _G3S )/P _G3S , where n _G is a quantity of gas 521 in the dump chamber 504 before the sample container 500 is run in hole (Equation 6).

[0162] For example, before sampling beings, the gas pressure Po and gas temperature To can be measured such that:

[0163] (VGas)o = VD = (n _G ^* R ^* To)/Po (Equation 7).

[0164] The volume of sample fluid 522 captured in the sample volume portion 512 of the sample chamber 502 can be estimated as:

[0165] Sample ⁼ Vs — Voil/Sample ⁼ Voil/Dump ⁼ VD ~ VGas ⁼ V _D - ( n _G *R* T _G as )/PG as

(Equation 8).

[0166] Based on the gas pressure Po and gas temperature To before sampling, the sample fluid volume Vsampie can be expressed as:

[0167] Vsampie = V _D (1 - (T _Gas /T ₀ ) ^* (Po/P _G as)) (Equation 9)

[0168] By measuring, P _GSS and T _GSS VS. time, the tool controller(s) 501 of FIG. 5 and/or the tool controller 1 18 of FIGS. 1-3 can determine the volume Vsampie of sample fluid captured in the sample volume portion 512 of the sample chamber 502 at time t based the following expression:

[0169] Vsampie(t) = VD (1 - ( TGas(t)/To )* {Po/ PGas(t))) (Equation 10). [0170] The volume of the sample fluid can be monitored overtime (e.g., a first time and a second time) as a result of changes in gas pressure over time due to movement of the piston 510. Although in the foregoing examples an ideal gas law is used as the equation of state for the gas 521 in the dump chamber 504, other expressions can be used with respect to the relationship between gas pressure, gas temperature, gas quantity, and/or sample volume.

[0171] In some examples, the dump chamber 504 of FIG. 5 is primed with additional gas 521 to increase a pressure of the gas above atmospheric pressure and to improve a sensitivity of changes in the gas pressure P _GBS relative to changes in the sample volume Vsampie. For example, as noted above in Equation 9, the relationship between Vsampie and PGas in the case of an ideal gas can be expressed as Vsampie = VD (1 - ( TGas/To)* (Po/PGas)). Also, a volume of gas 521 in the dump chamber 504 can be expressed as a fraction of the volume VD of the dump chamber 504:

[0172] VGas = x * VD (Equation 1 1).

[0173] The sensitivity of the gas pressure P _GBS to a change in sample fluid volume Vsa _mpie can be expressed as:

[0174] d Vsampie = PolTo* Vo* TGas * SPcas/Pcas ² (Equation 12); or

[0175] 5 Vsampie = VD* TGas /To*5PGas/Po*x ² (Equation 13); or

[0176] 5PG3S = To/TGas /VD*Po/x ² *5 Vsampie (Equation 14).

[0177] Therefore, for a given x, 5P _G3S is proportional to Po. Priming the dump chamber 504 with additional gas so that the gas pressure is above atmospheric pressure can improve measurement sensitivity with respect to estimating the sample fluid volume Vsampie based on gas pressure PGas-

[0178] FIG. 6 illustrates a second example sampling device or sample container 600 that may be used to estimate sample fluid volume over time substantially as disclosed above with respect to the first example sample container 500 of FIG. 5. The sample container 600 of FIG. 6 may be implemented with, for example, the sample platforms 106, 200, 300 of FIGS. 1-3 to serve as a volume changer. [0179] The example sample container 600 of FIG. 6 includes an inlet 601 , a sample chamber 602, and a dump chamber 604 defined by a housing 605 of the sample container 600. The inlet 601 can include a flow control valve and/or a trigger substantially as disclosed above with respect to the sample containers 400, 500 of FIGS. 4 and 5. The dump chamber 604 of the sample container 600 of FIG. 6 includes a compressible fluid such as gas 606 disposed therein. The sample chamber 602 includes a sample volume portion 608 for holding sample fluid 610 and a hydraulic fluid portion 612 for holding hydraulic fluid 614 (e.g., hydraulic oil). In the example of FIG. 6, a moveable separator 616 separates the sample volume portion 608 from the hydraulic fluid portion 612.

[0180] In the example of FIG. 6, a flow restrictor or orifice 618 is disposed between the sample chamber 602 and the dump chamber 604. The example sample container 600 of FIG. 6 includes a flow control valve 620 to control a flow of the hydraulic fluid 614 from the hydraulic fluid portion 612 to the dump chamber 604. In the example of FIG. 6, the flow control valve 620 includes a seal having a female part 622 coupled to the flow restrictor 618. A male part 624 of the seal is coupled to a rod 626 (e.g., a firing rod) disposed in the dump chamber 604. In some examples, the female part 622 and the male part 624 include metal. In the example of FIG. 6, when the female part 622 and the male part 624 engage, the hydraulic fluid 614 in the sample chamber 602 is sealed from the dump chamber 604.

[0181] The rod 626 of the sample container 600 of FIG. 6 is controlled by an actuator 628 that moves the rod 626 to selectively cause the female part 622 and the male part 624 to engage or disengage. For example, during sampling, the actuator 628 causes the male part 624 of the seal to disengage from the female part 622 to allow hydraulic fluid 614 to flow into the dump chamber 604 to increase a volume of sample fluid 610 collected in the sample volume portion 608 of the sample chamber 602. Thus, the actuator 628 acts a volume changer driver with respect to the sample fluid 610 when the sample container 600 is implemented with the sample platform(s) 106, 200, 300 of FIGS. 1-3. The actuator 628 is communicatively coupled to one or more tool controller(s) 630 (e.g., the tool controller 1 18 of FIGS. 1-3, a dedicated tool controller). The tool controller(s) 630 provide instructions to the actuator 628 based on, for example, commands received from the surface processor 1 12 of FIG. 1 . In some examples, an acoustic telemetry system is used for communication between the actuator 628 and the surface.

[0182] In the example of FIG. 6, the rod 626 includes one or more sensor(s) 632 to measure pressure and temperature of the gas 606 in the dump chamber 604. The sensor(s) 632 are communicatively coupled to the tool controller(s) 630. Based on the gas pressure PGas(t) and the gas temperature Teas(t) measured by the sensor(s) 632, the tool controller(s) 630 can estimate a volume of sample in the sample chamber 602 over time (i.e., Vsam _P ie(t)) substantially as disclosed above in connection with FIG. 5.

[0183] Thus, the example sample containers 500, 600 of FIGS. 5 and 6 provide for the determination or estimation of the sample fluid volume over time (i.e., Vsampie(t)) based on the measurement of gas temperature over time (i.e., Teasft)) and gas pressure over time (i.e., PGas(t)). The volume measurements can be used to monitor, for example, fluid volume expansion at the sample platform(s) 106, 200, 300 FIGS. 1-3. As disclosed herein, the example sample containers 500, 600 of FIGS. 5 and 6 can be used by the surface operator and/or the fluid analyzer 120 of the downhole tool controller 1 18 to monitor sampling of the sample fluid over time, to control sample flow rate, and/or to conduct one or more PV or PVT analyses based on the data obtained via the example sample containers 500, 600 of FIGS. 5 and 6.

[0184] Example sample containers for collecting sample fluid and determining a volume of sample fluid collected over time are not limited to the example sample containers 500, 600 illustrated in FIGS. 5 and 6. Rather, such an example sample container can include other designs having a moving mechanical device (e.g., a piston) and a chamber defining a closed volume, where movement of the mechanical device changes a volume of the chamber. In such example containers, the chamber can include a quantity of compressible fluid (e.g., a gas) that can be characterized by an equation of state f(P, V, T). In some examples, the chamber includes an incompressible sample fluid (e.g., a liquid having a small compressibility xi relative to a compressibility x ₂ of gas). The pressure of the compressible fluid can be monitored (e.g., via sensors, a downhole controller, a surface processor) to determine the volume of the compressible fluid and, thus, the volume of sample collected over time as disclosed herein.

[0185] In other examples, the sample container(s) 400, 500, 600 include a position sensor disposed, for example, on the piston 410, 510 of the sample container(s) 400, 500 of FIGS. 4 and 5 and/or the moveable separator 616 of FIG. 6 of the sample container 600 of FIG. 6. The position data obtained by tracking motion of the piston and/or rod can be used to monitor sample fluid volume as a function of time (e.g., VFiuid(t)). Thus, in some examples, the sample fluid volume can be monitored during, for example, depressurization of the sample without measuring the pressure of a compressible fluid (e.g., gas) disposed in the dump chamber of the sample container(s) 400, 500, 600.

[0186] As disclosed herein, in some examples, the sample platform(s) 106, 200, 300 and/or volume changer(s) 212, 312, 400, 500, 600 include phase nucleation device(s) to facilitate phase changes during depressurization or pressurization of the sample fluid. FIG. 7 is an example optical probe 700 associated with a first phase nucleation device 702 that may be implemented with the example sample platform(s) 106, 200, 300 of FIGS. 1-3. For example, the optical probe 700 (e.g., a sensor 216, 318 of FIGS. 2, 3) can be disposed in the chamber 203 of the sample platform 200 of FIG. 2 or the chamber 305 of the sample container 300 of the sample platform 300 of FIG. 3.

[0187] The example optical probe 700 of FIG. 7 can be used to detect a presence of gas (e.g., gas bubbles) and/or liquid (e.g., liquid droplets) in sample fluid (e.g., the sample fluid collected in the chamber 203 of FIG. 2 and/or the chamber 305 of the sample carrier 302 of FIG. 3). The optical probe 700 of FIG. 7 includes a tip 704 (e.g., a sapphire tip) that is exposed to the sample fluid. The optical probe 700 of FIG. 7 includes an optical fiber bundle including a light emitting diode and a photodiode (not shown). The optical fiber bundle injects light from the LED into the tip 704 and, thus, the sample fluid. The optical probe 700 collects light reflected back via the photodiode. For example, reflection of the light is high in the presence of gas and low in the presence of liquid based on the refractive index of the fluid in contact with the optical probe 700. Based on the detection of light received back at the photodiode, the amount of gas bubbles in the liquid phase of the sample fluid or the amount of liquid in the gas phase of the sample fluid can be determined (e.g. by the fluid analyzer 120 of the tool controller 118, the surface processor 1 12 of FIG. 1 ).

[0188] In the example of FIG. 7, the first phase nucleation device 702 includes a heating coil 706. The heating coil 706 facilitates a phase transition during, for example, depressurization of the sample fluid via the volume changers (e.g., the volume changer(s) 212 of FIG. 2, the sample containers 312 of FIG. 3). For example, the phase nucleation device 702 can facilitate the formation of gas bubbles in liquid. The location of the tip 704 of the optical probe 700 proximate to the heating coil 706 enables the optical probe 700 to collect data substantially at the start of the phase transition.

[0189] FIG. 8 illustrates an optical probe 800 associated with a second phase nucleation device 802 that may be implemented with the example sample platform(s) 106, 200, 300 of FIGS. 1-3. For example, the optical probe 800 (e.g., a sensor 216, 318 of FIGS. 2, 3) can be disposed in the chamber 203 of the sample platform 200 of FIG. 2 or the chamber 305 of the sample container 300 of the sample platform 300 of FIG. 3. In the example of FIG. 8, the second phase nucleation device 802 includes a propeller 804 operatively coupled to a motor 806. The propeller 804 agitates the sample fluid to facilitate a phase transition. A tip 808 of the example optical probe 800 of FIG. 8 is disposed proximate to the propeller 804 to detect the presence of gas bubbles and/or liquid droplets substantially at the start of the phase transition.

[0190] Fig. 9 is a block diagram of the example formation fluid analyzer system 100 of FIGS. 1-8 including the example fluid analyzer 120 that may be implemented by the example tool controller(s) 1 18, 401 , 501 , 630 of FIGS. 1-6. The example fluid analyzer 120 implements one or more instructions received from the surface processor 1 12 via the telemetry system 1 1 1 to control of one or more sample platforms (e.g., the example sample platform(s) 106, 200, 300 of FIGS. 1-3). In some examples, the fluid analyzer 120 automatically controls the sample platform(s) based on sensor data and one or more rules implemented by the fluid analyzer 120. Although the example fluid analyzer 120 of FIG. 9 is discussed in connection with the example downhole tool controller 1 18 of FIGS. 1-3, one or more of the components of the example fluid analyzer 120 could be implemented by one or more processors, including, for example, other downhole tool controllers and/or the surface processor 1 12 of FIG. 1.

[0191] The example fluid analyzer 120 of FIG. 9 includes a database 900 to store signal data generated by one or more of the sensors 109, 216, 217, 218, 316, 318, 524, 632 and transmitted to the fluid analyzer 120 via the tool bus 1 14. The database 900 can be associated with, for example, a memory of the tool controller 1 18.

[0192] For example, the data can include sample fluid property data 902 generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800. The sample fluid property data 902 can include measurements with respect to fluid properties such as density, viscosity, etc. In some examples, the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 are associated with phase nucleation devices 222, 320, 702, 802 and the fluid property data 902 includes data indicative of the formation of gas bubbles, liquid droplets, and/or solid particles.

[0193] The data generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can include sample fluid pressure measurements or fluid pressure data 904. In some examples, the data generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 include downhole temperature data 906 with respect to a temperature of a downhole environment. The sample fluid pressure data 904 and/or the downhole temperature data 906 can include respective time-correlated pressure and/or temperature data. In some examples, the downhole temperature data 906 is correlated with downhole depth.

[0194] In some examples, the data generated by the sensor(s) 524, 632 includes gas pressure data 907 with respect to a pressure of a gas disposed in a dump chamber of a sample container, such as the example sample containers 500, 600 of FIGS. 5 and 6. In some examples, the data generated by the sensor(s) 524, 632 includes gas temperature data 908 of the gas disposed in the dump chamber of the sample container (e.g., the sample container(s) 500, 600 of FIGS. 5 and 6). [0195] The example fluid analyzer 120 of FIG. 9 includes a data analyzer 909. The example data analyzer 909 performs one or more data processing techniques such as converting the signal data 902, 904, 906, 907, 908 from analog to digital data, filtering the data, removing noise from the signal data, compressing the data, etc. The processed data can be stored in the database 900.

[0196] The example fluid analyzer 120 of FIG. 9 includes a communicator 910. The communicator 910 generates one or more instructions to enable transmission of the sensor data 902, 904, 906, 907, 908 (e.g., the processed data) between the tool controller 1 18 and the surface processor 1 12 via the downhole-to-surface bi- directional telemetry system 1 1 1 of FIG. 1.

[0197] The example communicator 910 can also receive instructions from the surface processor 1 12 via the telemetry system 11 1. An operator can provide one or more user inputs 912 via the surface processor 1 12 with respect to, for example, a duration of time that the sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 should collect data. The user input(s) 912 (e.g., instructions or commands) are transmitted downhole via the telemetry system 1 1 1 and received by the communicator 910 of the fluid analyzer 120. In some examples, the user input(s) 912 are stored in the database 900.

[0198] In some examples, based on the sensor data 902, 904, 906 generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 and transmitted to the surface via the telemetry system 1 11 , the surface processor 1 12 analyzes one or more fluid properties versus time, pressure, or volume (e.g., pressure-volume (PV) analysis). In some examples, the sensor data 902, 904, 906 includes downhole temperature data and the surface processor 1 12 performs a pressure-volume-temperature (PVT) analysis. In other examples, the PV analyses and/or the PVT analyses are performed downhole by the fluid analyzer 120 of FIG. 9. In such examples, the results of the PV and/or PVT analyses can be transmitted to the surface processor 1 12 and used by the operator to, for example, adjust one or more parameters of the well test, optimize the well test, and/or provide other user input(s) 912 for the well test. In other such examples, the fluid analyzer 120 automatically generates one or more instructions based on the PV and/or PVT analyses results. [0199] For example, the fluid analyzer 120 of FIG. 9 includes a rules manager 914. The example rules manager 914 applies one or more rules 916 (e.g., algorithms) to perform PV analyses and/or PVT analyses. In some examples, the rules manager 914 applies the rules 916 to determine a volume of sample fluid collected by the volume changer(s) 212, 312, 400, 500, 600 overtime as substantially disclosed above in connection with FIGS. 5 and 6. The rule(s) 916 can be stored in the database 900 of FIG. 9.

[0200] The rule(s) 916 executed by the example rules manager 914 of FIG. 9 can be based on one or more user inputs (e.g., the user input(s) 912) received by the fluid analyzer 120. In some examples, the rule(s) 916 are previously programmed in the fluid analyzer 120 before the tool controller 118 is disposed downhole. In other examples, the rule(s) 916 and/or modifications to the rule(s) 916 are received by the fluid analyzer 120 from the surface processor 1 12 via the telemetry system 1 11 after the tool controller 1 18 is disposed downhole. In some examples, the rule(s) 916 and/or modification(s) to the rule(s) 916 are received in substantially real-time based on the sensor data 902, 904, 906, 907, 908. For example, the sensor data 902, 904, 906, 907, 908 can be sent to the surface processor 1 12 in addition to being analyzed downhole by the rules manager 914. In such examples, an operator may wish to modify one or more of the rule(s) 916 applied by the rules manager 914 based on the sensor data 902, 904, 906, 907, 908.

[0201] The example fluid analyzer 120 of FIG. 9 can implement PV and/or PVT analysis workflows based on the rule(s) 916 stored in the database 900 and/or the user input(s) 912 received from the surface (e.g., received in substantially real-time). For example, the rules manager 914 can generate sample platform control instruction(s) 918 directing the control valve(s) 108, 1 10, 204, 208, 306, 308 of the sample platforms(s) 106, 200, 300 to selectively open to enable fluid to flow through the sample platform(s) 106, 200, 300 or close to capture the fluid in the sample platform(s) 106, 200, 300 (e.g., in the sample chamber 203 of the sample platform 200 of FIG. 2, the sample chamber 305 of the sample platform 300 of FIG. 3) as the fluid flows through the production tubing 102. The sample platform control instruction(s) 918 are transmitted to the sample platform(s) 106, 200, 300 via the tool bus 1 14. In some examples, the rules manager 914 determines that the control valves 108, 1 10, 204, 208, 306, 308 should be closed to capture the fluid based on the sensor data 902, 904, 906, 907, 908 in view of the rule(s) 916. For example, the rules manager 914 can determine that the fluid should be captured if the fluid property data 902 meets a particular (e.g., predefined) threshold, such as a density threshold.

[0202] After the sample platform(s) 106, 200, 300 capture the sample fluid, the rules manager 914 generates instruction(s) 918 directing the volume changer(s) 212, 312, 400, 500, 600 to depressurize the sample fluid collected by the sample platform(s) 106, 200, 300. The rules manager 914 determines that the volume changer(s) 212, 312, 400, 500, 600 should be activated based on the rule(s) 916 and/or user input(s) 912 received from the surface indicating that PV and/or PVT analyses are to be performed.

[0203] In examples where the volume changer(s) 212, 312, 400, 500, 600 include sample container(s) 312, 400, 500 having trigger(s) 314, 409, 509, the sample platform control instruction(s) 918 include instructions directing the trigger(s) 314 to open the sample container(s) 312. The sample platform control instruction (s) 918 can include instruction(s) controlling selective movement of piston(s) and/or rods 410, 510, 626 of the volume changer(s) 212, 312, 400, 500, 600 to depressurize or pressurize the sample fluid collected by the sample platform(s) 106, 200, 300. In some such examples, the sample platform control instruction(s) 918 include instructions for the volume changer(s) 212, 312, 400, 500, 600 to alternate between depressurizing and pressurizing the sample fluid. In some examples, the sample platform control instruction(s) 918 include instructions directing the phase nucleation device(s) 222, 320, 702, 802 to facilitate a phase transition during, for example, depressurization of the sample fluid.

[0204] The example rules manager 914 of FIG. 9 generates one or more monitoring instructions 920 directing the sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800, of the sample platform(s) 106, 200, 300 to monitor one or more fluid properties, fluid pressure, gas pressure, etc. over time. The monitoring instruction(s) 920 can be transmitted to the sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 via the communicator 910 and the tool bus 1 14. The sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 collect data with respect to, for example, sample fluid properties, sample fluid pressure, downhole temperature, etc., over one or more measurement cycles.

[0205] The example rules manager 914 of FIG. 9 analyzes the fluid property data 902, the fluid pressure data 904, and/or the downhole temperature data 906 generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800. The example rules manager 914 applies the rule(s) 916 (e.g., algorithms) to the sensor data 902, 904, 906 to analyze one or more fluid properties against time, pressure, and/or volume. In some examples, the rules manager 914 applies the rule(s) 916 to the gas pressure and/or gas temperature data 907, 908 collected by sensor(s) 524, 632 disposed in a dump chamber of a volume changer (e.g., the sample container(s) 500, 600 of FIGS. 5 and 6) to determine sample fluid volume overtime during, for example, depressurization of the sample fluid.

[0206] The examples rules manager 914 of FIG. 9 generates one or more analysis results 922 based on the PV and/or PVT analyses. In some examples, the PV and/or PVT analysis results 922 are transmitted to the surface processor 1 12 by the communicator 910 of the fluid analyzer 120 via the telemetry system 11 1. In some examples, the analysis result(s) 922 include estimates of sample volume fluid over time during, for example, despressurization of the sample fluid. Based on the analysis result(s) 922, the surface operator may provide user input(s) 912 via the surface processor 1 12 with respect to the performance of the well test, the collection of the sample fluid, the flow of fluid through the sample platform(s) 106, 200, 300, etc.

[0207] In some examples, the rules manager 914 of FIG. 9 automatically determines that one or more actions should be taken based on the analysis result(s) 922. For example, the rules manager 914 can generate sample platform control instruction(s) 918 directing the volume changer(s) 212, 312, 400, 500, 600 to alternate between depressurizing the sample fluid and pressurizing the sample fluid (e.g., via movement of the volume changer driver(s) 214, piston(s) 410, 510, and/or rod(s) 626) to generate sensor data over one or more measurement cycles. In some such examples, the rules manager 914 can analyze the sensor data 902, 904, 906, 907, 908 for each measurement cycle, for example, to verify the repeatability of the sensor data.

[0208] The example fluid analyzer 120 of FIG. 9 includes a report generator 924. The report generator 924 of FIG. 9 generates one or more fluid phase diagrams 926 based on the PV and/or PVT analysis result(s) 922. The fluid phase diagram(s) 926 indicate the conditions (e.g., reservoir pressure, reservoir temperature) at which different phase transitions occur. The fluid phase diagram(s) 926 can be stored in the database 900 for use by the fluid analyzer 120 in implementing the rule(s) 916 (e.g., the algorithms) and/or transmitted to the surface processor 1 12 via the telemetry system 1 1 1 for analysis at the surface.

[0209] In some examples, the rules manager 914 of FIG. 9 generates sample platform control instruction(s) 918 instructing the control valves 108, 1 10, 204, 208, 306, 308 to re-open to enable the flow of fluid to resume through the production tubing 102 via the sample platform(s) 106, 200, 300 after the analyses are complete. In some examples, the fluid analyzer 120 receives a user input 912 instructing the control valves 108, 1 10, 204, 208, 306, 308 to re-open. In the some examples, the sample platform control instruction(s) 918 and/or the user input(s) 912 direct the volume changer(s) 212, 312, 400, 500, 600 to release the fluid from the volume changer(s) 212, 312, 400, 500, 600.

[0210] Thus, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to analyze fluid properties with respect to time, temperature, pressure, and/or volume. Examples of analyses that may be performed by the example system 100 of FIGS. 1- 9 include, but are not limited to, bubble point pressure detection, asphaltene detection, fluid compressibility measurements, etc.

[0211] For example, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to determine bubble point pressure of sample fluid collected by the sample platform(s) 106, 200, 300. For a liquid, a transition from liquid to a gas-liquid (e.g., a formation of a first bubble of gas) under particular pressure and temperature conditions is known as a bubble point. The presence of gas in the fluid flowing in the production tubing due to, for example, pressure differentials between fluid at the reservoir and fluid in the production tubing may result in the collection of unrepresentative fluid samples during sampling. Also, the presence of gas in the reservoir can affect an analysis of a pressure buildup test that may be used to evaluate reservoirflow characteristics. Thus, determining the pressure at which gas first begins to form liquid (i.e. , the bubble point pressure) can be instructive to, for example, the surface operator, with respect to determining flow and/or sampling strategies.

[0212] The example sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 can include one or more gas bubble detectors. The gas bubble detector(s) can include an optical probe associated with a phase nucleation device, as substantially disclosed above in connection with the optical probe 700 and phase nucleation device 702 of FIG. 7 (e.g., facilitating phase nucleation using heat) and/or the optical probe 800 and phase nucleation device 802 of FIG. 8 (e.g., facilitating phase nucleation using mechanical agitation).

[0213] To measure bubble point pressure, sample fluid is captured by the sample platform(s) 106, 200, 300 by closing the sample platform control valves 108, 1 10, 204, 208, 306, 308 (e.g., based on a sample platform control instruction 918 generated by the fluid analyzer 120 of FIG. 9 and/or based on a user input 912 received from the surface). The volume changer(s) 212, 312, 400, 500, 600 of the sample platform(s) 106, 200, 300 are selectively activated (e.g., by the tool controller 1 18, the surface processor 1 12) to depressurize the sample fluid collected by the sample platform(s) 106, 200, 300. The phase nucleation devices 702, 802 can facilitate the phase transition during the depressurization and the gas bubble detector (e.g., the optical probe(s) 700, 800) can monitor a bubble count Bcount over time. The sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 of the example sample platform(s) 106, 200, 300 can measure sample fluid pressure.

[0214] In such examples, the bubble count data Bcount can be analyzed by the surface processor 1 12 and/or the fluid analyzer 120 of the tool controller 1 18 to determine bubble point pressure. For example, a rule 916 may be stored in the database 900 of the fluid analyzer 120 of FIG. 9 indicating that the bubble count Bcount is expected to increase sharply when the bubble point is reached. The rules manager 914 can use the rule 916 to determine or estimate the bubble point pressure Peu _bbi e based on the bubble count Bcount.

[0215] In some examples, the bubble point pressure Peu _bbi e (e.g., an analysis result 922) is transmitted to the surface processor 112 via the telemetry system 1 11 and downhole fluid analyzer 120. In some examples, the fluid analyzer 120 uses the bubble point pressure PBu _bbi e to adjust the flow rate of fluid through the production tubing 102. For example, the control valves 108, 1 10, 204, 208, 306, 308 can be re- opened to allow the formation fluid to flow through the sample platform(s) 106, 200, 300. The sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 of the sample platform(s) 106, 200, 300 can monitor formation fluid pressure. Based on the pressure sensor data, the surface operator (e.g., via the surface processor 1 12) and/or the downhole fluid analyzer 120 can adjust the formation fluid flow rate in the production tubing 102 so that the pressure in the tubing remains above the bubble point pressure Peu _bbi e.

[0216] As disclosed herein, in some examples, the sample containers 500, 600 of FIGS. 5 and 6 can be used to monitor sample fluid volume over time during, for example, expansion of the sample fluid volume (e.g., Vsam¹e(t)). In such examples, the bubble point pressure Peu _bbi e can be monitored with respect to sample fluid volume. In other examples, the relationship between bubble point pressure Peu _bbi e and sample fluid volume is based on a known volume of the sample container (e.g., the sample container 400 of FIG. 4) when the sample container is filled or substantially filled with sample fluid.

[0217] In some examples, the formation fluid analyzer system 100 of FIGS. 1-9 determines dew point pressure, or a pressure at which liquid (e.g., condensate) forms in gas. The dew point pressure can be determined substantially as disclosed above with respect to determining the bubble point pressure using the optical probes 700, 800 and, in some examples, the phase nucleation devices 702, 802 of FIGS. 7 and 8 disposed in the sample platforms 106, 200, 300 of FIGS. 1-3.

[0218] As another example, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to detect formation of asphaltene in sample fluid captured by the sample platform(s) 106, 200, 300. For example, the sample platform(s) 106, 200, 300 can include optical sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 to detect asphaltene formation during depressurization of the sample fluid via the volume changer(s) 212, 312, 400, 500, 600.

[0219] The optical sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can include, for example, a microscopic video imager. The optical sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can include a particle size analyzer to estimate a size distribution of solid particles detected in the sample fluid via video imaging. The detection of solid particles can be used by the surface processor 1 12 and/or the fluid analyzer 120 of the tool controller 1 18 to determine an asphaltene on-set pressure PAsphiatente. One or more rule(s) 916 can be implemented by the rules manager 914 of the example fluid analyzer of FIG. 9 with respect to, for example, detecting asphaltene in the sample fluid based on a particular (e.g., predefined) threshold particle size.

[0220] In some examples, the optical sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 include laser sensor(s) to detect solid particles due to asphaltene formation. The formation of solid particles in fluid can cause light transmitted into the sample fluid to scatter. The example laser sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can transmit laser light into the sample fluid collected by the sample platform(s) 106, 200, 300. The light emitted by the laser sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 is detected by a photodetector (e.g., another sensor 109, 216, 217, 218, 316, 318, 700, 800) disposed in the sample platform(s) 106, 200, 300. One or more rule(s) 916 stored in the database 900 of the example fluid analyzer 120 of FIG. 9 can include a threshold light scattering level for detecting an onset of asphaltene formation in the fluid based on an amount of light detected by the photodetector. Based on the rule(s) 916 and the amount of light detected by the photodetector, the rules manager 914 of the fluid analyzer 120 can determine or estimate the asphaltene on-set pressure

P Asphlatente-

[0221] The use of optical sensor(s) is not limited to asphaltene detection. In some examples, the sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 include optical sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 detect wax formation in the fluid substantially as disclosed above with respect to detection of asphaltene. [0222] As another example, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to estimate fluid isothermal compressibility. Fluid isothermal compressibility x _T can be defined as:

[0223] x _T = (Equation 15)

[0224] For example, pressure sensor(s) 216, 316 of the sample platform(s) 106, 200, 300 can measure sample fluid pressure Pnuid_o after the sample fluid is captured by the sample platform(s) 106, 200, 300 (e.g., in the sample chamber 203 of the sample platform 200 of FIG. 2, the sample chamber 305 of the sample platform 300 of FIG. 3). As disclosed herein, the volume of the sample fluid collected by the sample platform(s) 106, 200, 300 is fixed and, thus, a volume of sample fluid Vsampie in the sample platform(s) 106, 200, 300 is known.

[0225] The volume changer(s) 212, 312, 400, 500, 600 can be activated (e.g., via the fluid analyzer 120 of the tool controller 1 18) to expand the volume of the sample fluid collected by the sample platform(s) 106, 200, 300. After the volume changer(s) 212, 312, 400 fully or substantially fully expand the sample volume, the expansion volume is known based on a volume Vsampier of the volume changer(s) 212, 312, 400. For example, the expansion volume Vsampier can be determined based on a maximum volume of the sample volume portion 412 of the sample container 400 when the piston 410 has moved so as to allow a maximum volume of sample fluid into the sample volume portion 412. Also, the sample fluid pressure Pfi _U id_i can be measured by the pressure sensor(s) 216, 316 when the volume changer(s) 212, 312, 400 have fully expanded the sample volume. Based on one or more rule(s) 916, the fluid isothermal compressibility x _T can be determined or estimated by the rules manager 914 using the equation:

assumption that Vsampier « Vsampie-

[0227] As another example, the sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 can be used to measure fluid compressibility x _T based on a density measurement. For example, fluid density pFiui _d can be defined as: [0228] (Equation 17).

[0229] During depressurization of the sample fluid by the volume changer(s) 212, 312, 400 rrisampie in Equation 2, above, remains constant. The isothermal compressibility x _T of the sample fluid during depressurization can be expressed as:

[0231] The example sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 can include sensor(s) capable of monitoring fluid density pFiui _d for a given pressure P. For example, the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can include a pressure gradiometer to measure a pressure gradient generated by the fluid density pFiui _d in a well oriented vertically relative to the surface. In some examples, the pressure gradient is measured using a differential pressure sensor or two absolute pressure sensors. For a static fluid, the pressure differential DR between two points spaced apart by a vertical distance h can be expressed as:

[0232] AP = pFiui _d gh (Equation 19).

[0233] Therefore, based on the pressure differential Dr, the fluid density pnui _d can be estimated and/or monitored by the rules manager 914 during e.g., depressurization of the sample fluid via the volume changer(s) 212, 312, 400.

[0234] In some examples, the volume changer(s) enable sample fluid volume to be measured over time during, for example, depressurization of the sample fluid as disclosed in connection with the example sample containers 500, 600 of FIGS. 5 and 6. In such examples, the fluid isothermal compressibility x _T and/or the fluid density PFiui _d can be determined based on the monitoring of the sample fluid volume over time.

[0235] For example, a fixed volume of sample fluid (VFiuid)o is collected by the sample platform(s) 106, 200, 300 (e.g., in the sample chamber(s) 203, 305 of the sample platform(s) 200, 300). During depressurization of the sample fluid via the volume changer(s) or the sample container(s) 500, 600 of FIGS. 5 and 6, the sample fluid volume Vsam _P ie(t) can be monitored over time. Thus, the sample fluid volume over time with respect to the sample platform(s) 106, 200, 300 can be expressed as: [0236] (VFuid)(t)— (VFIuid)o ⁺ Vsample(t) (Equation 20).

[0237] Sample fluid pressure P _fiuid (t) can be measured by the pressure sensor(s) 216, 316. Based on the volume and pressure measurements over time sample fluid volume Vnui _d can be determined by:

[0238] V Fluid ⁼ Q(P Fluid) (Equation 21).

[0239] Equation 21 , above, provides for a determination of fluid isothermal compressibility x _T as a function of pressure (e.g., x _T (P _Fiuid )) using Equation 18, above.

[0240] The monitoring of sample fluid volume over time during the expansion of the sample fluid at the sample platform(s) 109, 200, 300 can also be used to monitor fluid density as function of pressure. For example, a pressure gradiometer can be used to estimate fluid density ( p _Fiuid )o before depressurization of the sample fluid begins via the volume changer(s) 500, 600. Based on Equation 21 above, sample fluid density can be determined as a function of pressure using the following expression:

[0241] (pFiuid)(P 'Fluid) = (pFiuid)o ^* ( V Fluid) o/(g ( P Fluid) ) (Equation 22).

[0242] As another example, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to estimate a compressibility factor Z when the sample fluid includes a mixture of, for example, oil and gas phases. For a given volume V of a real gas, the Z factor is defined as:

[0243] pV= ZnRT, where n= an amount of substance; R is a gas constant (e.g., 8.314 J.K ¹ ); and T is temperature (Equation 23).

[0244] In this example, fluid isothermal compressibility x _T can be defined as:

1° ²⁴⁵ 1 T = ? (¾. = i (¾. ⁺ ? (Equation 24).

[0246] Equation 24 can be used to estimate the compressibility factor Z (p) as follows: [0247] Z = Po is a reference pressure within a

pressure range (Pmin, Pmax) during a pressure-volume (PV) measurement cycle (Equation 25).

[0248] The rules manager 914 of the example fluid analyzer 120 of FIG. 9 can determine x _T (P) and P exp x _T (P)dP ) base on sensor data and the rule(s)

916. In the foregoing example, Zo IPo can be estimated from a surface measurement taken from a sample (e.g., a sample collected downhole) and transmitted to the rules manager 914 as a user input 912.

[0249] As disclosed herein, the example formation fluid analyzer system 100 of FIGS. 1-9 can be used to conduct PVT analyses. For example, PV analysis results such as bubble point pressure can be determined at different temperatures. In a downhole environment such as the wellbore 104 of FIG. 1 , a formation temperature T generally increases with increasing depth away from the surface due to a geothermal gradient. As illustrated in FIG. 1 , a plurality of sample platforms 106, 200, 300 can be disposed in the wellbore 104 at different depths Zk, where the formation temperature at each depth is Tk. As the formation fluid moves toward the surface, the temperature of the fluid is lowered as the fluid cools.

[0250] When the formation fluid is captured by the example sample platform(s) 106, 200, 300 at the respective depths Z , the temperature of the fluid is reduced as compared to an initial temperature of the fluid at the reservoir. However, the temperature of the fluid is different (e.g., warmer than) the formation temperature T at the depth Zk at which the sample platform is located. Over time, the temperature of the sample fluid in the sample platform(s) 106, 200, 300 substantially equilibrates with the temperature Tk at the depth Zk at which the sample fluid has been captured. Thus, the example formation fluid analyzer system 100 of FIGS. 1-9 enables PV analyses to be performed at different temperatures Tk. In some examples, the PV analysis is performed before thermal equilibrium is reached or substantially reached between the fluid temperature and the formation temperature Tk. Thus, the example system 100 of FIGS. 1-9 enables fluid properties to be analyzed with respect to temperature. [0251] For example, FIG. 10 is an example phase diagram 1000 including data collected from sample fluid captured by a plurality of sample platforms 106, 200, 300 disposed at different depths ZA _T in the wellbore 104. In the example of FIG. 10, the surface processor 1 12 and/or the fluid analyzer 120 of the tool controller 1 18 perform the PV analyses (e.g., bubble point pressure, dew point pressure) at different temperatures Tk corresponding to the locations of the different sample platforms 106, 200, 300 at different depths Zk. For example, the phase diagram 1000 of FIG. 10 includes data as a function of temperature TV at depth z _? as represented by the line 1002 in FIG. 8, temperature T2 at depth z ₂ as represented by the line 1004 in FIG. 10, temperature T ₃ at depth Z3as represented by the line 1006 in FIG. 10, and temperature T4 at depth z ₄ as represented by the line 1008 in FIG. 10. The example phase diagram 1000 can be generated by the report generator 924 of the example fluid analyzer 120 of FIG. 9 based on the analysis results 922 determined by the rules manager 914.

[0252] In some examples, the PV analyses are performed as the fluid temperature changes relative to the formation temperature T at the depth Zk. Thus, the PV analyses can be performed over a range of temperatures to monitor fluid properties as the fluid temperature changes. For example, the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 of the sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 can generate fluid property data at a first time during a PV cycle (e.g., as depressurization begins via activation of the volume changer(s) 212, 312, 400, 500, 600) and at a second time during the PV cycle (e.g., when the volume changer(s) 212, 312, 400, 500, 600 have fully expanded the sample fluid volume).

[0253] For example, FIG. 1 1 is an example phase diagram 1100 including data collected from a sample fluid captured by an example sample platform 106, 200, 300 of FIGS. 1-3 and 9 disposed at a depth Zk having a formation temperature Tk at different times as, for example, the sample fluid is depressurized. For example, the phase diagram 1 100 of FIG. 1 1 includes data with respect to the pressure and temperature of the sample fluid at the beginning of the PV cycle as represented by point 1 102 in the phase diagram 1 100 and at the end of the PV cycle as represented by point 1 104 in the phase diagram 1 100. The example phase diagram 1 100 can be generated by the report generator 924 of the example fluid analyzer 120 of FIG. 7 based on the analysis results 922 determined by the rules manager 914.

[0254] As disclosed herein, the volume changers 212, 312, 400, 500, 600 of the sample platform(s) 106, 200, 300 can selectively depressurize and pressurize the sample fluid at the sample platform(s) 106, 200, 300. Thus, the sample platforms(s) 106, 200, 300 can be used to perform multiple PV cycles as the fluid temperature equilibrates or substantially equilibrates with the formation temperature Tk at the depth

Zk.

[0255] For example, FIG. 12 is an example phase diagram 1200 including data collected from a sample fluid captured by a sample platform 106, 200, 300 of FIGS. 1-9 disposed at a depth Zk having a formation temperature T during multiple PV cycles, including a first cycle 1201 , a second cycle 1202, and a third cycle 1203. The sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can collect data during depressurization and pressurization of the sample fluid over each of the PV cycles including, for example, the pressure at the start of each cycle (e.g., the start of depressurization or pressurization) and the end of the each cycle (e.g., complete or substantially complete depressurization or pressurization).

[0256] As another example, the formation fluid analyzer system 100 of FIGS. 1-9 can be used to generate reservoir models based on the pressure-volume-temperature (PVT) behavior of the formation fluid. In some known examples, a black oil PVT model is used for reservoir modeling to reduce costs and/or time as compared building a reservoir model based on a PVT and fluid compositions analyses performed at the surface. A black oil model can be based on a gas-to-oil ratio (GOR) estimated by a surface separator located at the surface. The example system 100 of FIGS. 1-9 can be used to increase an accuracy of a black oil model. In particular, one or more PV and/or PVT results determined by the fluid analyzer 120 of the example downhole tool controller 1 18 of FIG. 9 can be used to generate and/or calibrate a black-oil model. For example, the bubble point pressure Pbubbie determined by the rules manager 914 of the fluid analyzer 120 of FIG. 9 can be used to calibrate the black-oil model. [0257] As another example in the context of black oil models, the example system 100 of FIGS. 1-9 can be used to monitor density with respect to pressure (e.g., P _Fiuid (p)). To create a black oil model, reservoir phase densities are calculated using formation volume factors (FVF), oil/gas solution ratios, and fluid density measured at the surface. The downhole monitoring of density as a function of pressure (e.g, PFiuid( Fiuid)) by the rules manager 914 of FIG. 9 can be used in addition to or as an alternative to the reservoir phase densities determined at the surface to calibrate the black oil model. Thus, the example system 100 of FIGS. 1-9 can be used to calibrate a black-oil model based on measurements determined by the example downhole fluid analyzer 120. In such examples, the system 100 of FIGS. 1-9 can substantially reduce the need for one or more PVT analyses to be performed at the surface to build and/or calibrate the black-oil model.

[0258] The data collected downhole by the example system 100 of FIGS. 1-9 can be used for purposes not limited to PV or PVT analyses. For example, the monitoring of sample fluid volume during, for example, depressurization of the sample fluid via the example volume changer(s) 500, 600 of FIGS. 5 and 6 can be used to control the sampling of the formation fluid. For example, the gas temperature Teas(t) and the gas pressure P _Gas (t) as measured by the sensor(s) 524, 632 of the example sample containers 500, 600 of FIGS. 5 and 6 and/or the determinations of VGas(t) and/or Vsampie(t) (e.g., by the rules manager 914 of FIG. 9 as disclosed above in connection with FIGS. 5 and 6) can be processed by the surface processor 1 12 and/or the fluid analyzer 120 of the tool controller 1 18 using one or more algorithms and compared to predefined thresholds for sample fluid quality. Based on the sample quality threshold comparisons, the surface operator and/or the processor(s) (e.g., the surface processor 1 12, the tool controller 1 18) can determine whether or not the sample fluid has been properly captured downhole. If the surface operator and/or the processor(s) determine that the sample fluid was not captured properly, then a decision can be made to collect additional sample fluid, to trigger another sample container to collect sample fluid, etc.

[0259] The evaluation of the sample quality based on the data collected and/or processed downhole increases efficiency with respect to the sampling process. For example, rather than triggering multiple sample containers to collect sample fluid, sample containers could be triggered only if additional sampling is needed, thereby reducing operational time and costs.

[0260] As another example, the monitoring of sample fluid volume during, for example, depressurization of the sample fluid via the example volume changer(s) 500 of FIG. 5 can be used to control sampling flow rate. As disclosed herein, the orifice or flow restrictor 516 of the example sample container 500 of FIG. 5 controls the flow of hydraulic fluid through the orifice 516 during sampling to provide for low-shock sampling. If the flow rate is too high, a pressure of the sample fluid may drop below the bubble point, thereby resulting in a non-representative sample. The monitoring of the sample fluid volume over time ( Vsam _P ie(t )) via the example sample container 500 of FIG. 5 provides for monitoring of sample flow rate (e.g., dVsampie/dt). Based on the monitoring of the sample flow rate, the flow control valve 518 of the sample container 500 of FIG. 5 can be adjusted (e.g., via instructions from the surface processor 1 12 and/or the tool controller 1 18) to control the sample flow rate in substantially real-time. For example, the rules manager 914 of the fluid analyzer 120 of FIG. 9 could execute a sampling flow rate control algorithm based on the sample flow rate dVsampie/dt and automatically generate sample platform control instruction(s) 918 to adjust and/or maintain the opening of the flow control valve 518 based on the analysis.

[0261] While an example manner of implementing the example fluid analyzer 120 is illustrated in FIGS. 1-3 and 9, one or more of the elements, processes and/or devices illustrated in FIGS. 1-3 and 9 may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way. Further, the example database 900, the example data analyzer 909, the example communicator 910, the example rules manager 914, the example report generator 924 and/or, more generally, the example fluid analyzer 120 of FIGS. 1-3 and 9 may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware. Thus, for example, any of the example database 900, the example data analyzer 909, the example communicator 910, the example rules manager 914, the example report generator 924 and/or, more generally, the example fluid analyzer 120 of FIGS. 1-3 and 9 could be implemented by one or more analog or digital circuit(s), logic circuits, programmable processor(s), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)) and/or field

programmable logic device(s) (FPLD(s)). When reading any of the apparatus or system claims of this patent to cover a purely software and/or firmware

implementation, at least one of the example database 900, the example data analyzer 909, the example communicator 910, the example rules manager 914, the example report generator 924 and/or, more generally, the example fluid analyzer 120 of FIGS. 1-3 and 9 is/are hereby expressly defined to include a non-transitory computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a compact disk (CD), a Blu-ray disk, etc. including the software and/or firmware. Further still, the example fluid analyzer 120 of FIGS. 1-3 and 9may include one or more elements, processes and/or devices in addition to, or instead of, those illustrated in FIGS. 1-3 and 9, and/or may include more than one of any or all of the illustrated elements, processes and devices.

[0262] FIG. 13 illustrates a flowchart representative of an example method 1300 that can be implemented to perform PV and/or PVT analyses downhole based on sensor data generated downhole from sample fluid. The method 1300 of FIG. 13 can be implemented by the example system 100 of FIGS. 1-9, including, for example, the example fluid analyzer 120 of the downhole tool controllers 1 18, 401 , 501 , 630 and/or the surface processor 1 12. The sample fluid can be collected in, for example, any of the sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 and any of the volume changer(s) 109, 212, 312, 400, 500, 600 of FIGS. 1-6.

[0263] The example method 1300 begins with communicatively coupling one or more sample platforms to a downhole-to-surface telemetry system (block 1302). For example, the sample platform(s) 106, 200, 300 of FIGS. 1-3 and 9 can be deployed downhole in the wellbore 104 (e.g., coupled to production tubing 102). The sample platform(s) 106, 200, 300 include control valve(s) 108, 1 10, 204, 206, 306, 308 that can be communicatively coupled to one or more controllers, such as the downhole tool controller 118, local tool controllers 401 , 501 , 630, and/or the surface processor 1 12 via the tool bus 1 14 and the telemetry system 1 1 1 of FIGS. 1-3 and 9. In some examples, the sample platform(s) 106, 200, 300 include local tool controllers coupled to the downhole tool controller 1 18 and/or the surface processor 1 12. The communicative coupling between the sample platform(s) 106, 200, 300 and the telemetry system 1 1 1 can be established via one or more wireless connections, wireline connections, or a combination of wireless and wireline connections.

[0264] The sample platform(s) 106, 200, 300 include volume changer(s) 212, 312, 400, 500, 600 (e.g., sample containers). In some examples, the volume changer(s) include trigger(s) 314, 409, 509, such as electromechanical actuators. In some examples, the volume changer(s) 212, 312, 400, 500, 600 include local tool controller(s) (e.g., the tool controllers 401 , 501 , 630 of FIGS. 4-6). The trigger(s) and/or the local tool controllers of the volume changer(s) can be communicatively coupled to the downhole tool controller 1 18 and, thus, the example telemetry system 1 11 of FIG. 1 via the tool bus 1 14.

[0265] The example method 1300 includes communicatively coupling one or more sensors to a downhole-to-surface telemetry system (block 1304). For example, the sample platform(s) 106, 200, 300 can include sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 disposed in (e.g., coupled to) the sample platform(s) 106, 200, 300 and/or the volume changer(s) 212, 312, 400, 500, 600 of the sample platform(s) 106, 200, 300. The sensor(s) can include pressure sensors, temperature sensors, optical probes, sensors to measure fluid density, fluid compressibility, etc. The sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 are communicatively coupled to the tool controller(s) 1 18, 401 , 501 , 630 and, thus, the telemetry system 1 1 1 via the tool bus 1 14. The communicative coupling between the sensor(s) 109, 216, 217, 218, 316, 318, 524, 632, 700, 800 and the telemetry system 1 1 1 can be established via one or more wireless connections, wireline connections, or a combination of wireless and wireline connections

[0266] The example method 1300 includes a decision whether to collect sample fluid at the sample platform(s) (block 1306). For example, as illustrated in FIG. 1 , the sample platform(s) 106, 200, 300 can be aligned with the production tubing 102 such that formation fluid flows through the sample platform(s) 106, 200, 300 from the reservoir to the surface. In the example of FIG. 13, the decision to collect the sample fluid can be made by one or more downhole tool controller(s) and/or one or more surface processor(s)

[0267] If a decision is made to collect sample fluid in the sample platform(s) 106, 200, 300, the example method 1300 includes activating control valve(s) of the sample platform(s) 106, 200, 300 to capture a sample of the formation fluid (block 1308). In the example of FIG. 13, the control valve(s) can be activated by one or more downhole tool controller(s) and/or one or more surface processor(s). For example, the fluid analyzer 120 of the downhole tool controller 118 can instruct the control valve(s) 108, 1 10, 204, 208, 306, 308 of the sample platform(s) 106, 200, 300 (e.g., via the communicator 910) to close to capture the sample fluid within the chamber 203, 305 of the sample platform(s) and, thus, interrupt the fluid flow path through the production tubing 102. The fluid analyzer 120 can generate the sample platform control instructions 918 directing the control valve(s) to close based on instructions generated by the rules manager 914 of the fluid analyzer 120 and/or based on instructions received from the surface processor 1 12.

[0268] The example method 1300 includes a decision whether to perform one or more pressure-volume (PV) and/or pressure-volume-temperature (PVT) analyses based on the sample fluid collected by the sample platform(s) (block 1310). In the example of FIG. 13, the decision to perform PV and/or PVT analyses can be made by one or more downhole tool controller(s) and/or one or more surface processor(s). If a decision is made to perform the PV and/or PVT analyses, the example method 1300 includes activating the volume changer(s) of the sample platform(s) (block 1312). For example, based on instructions from the tool controller(s) 1 18, 401 , 501 , 630 and/or the surface processor 112, the volume changer(s) 212, 312, 400, 500, 600 of FIGS. 1 can be triggered to open via the trigger(s) 314, 409, 509 to enable sample fluid captured by the sample platform(s) 106, 200, 300 to flow into the volume changer(s) 212, 312, 409, 509. The volume changer(s) 212, 312, 400, 500, 600 include volume change driver(s) 214, 410, 510, 628 (e.g., piston(s)) that enable sample fluid to be captured in the sample chamber(s) 402, 502, 602 of the volume changer(s) 212, 300, 400, 500, 600. As the sample fluid is collected in the volume changer(s) 212, 300, 400, 500, 600, the sample fluid is depressurized. Put another way, the volume of the fluid is expanded relative to the sample platform(s) 106, 200, 300 via the activation of the volume changer(s) 212, 312, 400, 500, 600.

[0269] The example method 1300 includes accessing sensor data generated by the sensor(s) for the sample fluid collected by the sample device(s) (block 1314). In the example of FIG. 13, the sensor data can be accessed by one or more downhole tool controller(s) and/or one or more surface processor(s). For example, the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 can generate fluid property data 902, fluid pressure data 904, and/or downhole temperature data 906. In some examples, the sensor(s) are disposed proximate to the phase nucleation device(s) 222, 302, 702, 802 that facilitate phase transitions. In examples where sample fluid volume can be monitored over time (e.g., via the sample container(s) 500, 600 of FIGS. 5 and 6), the sensor(s) 524, 632 can generate gas pressure data 907 and gas temperature data 908 with respect to a compressible fluid disposed in the dump chamber(s) 504, 604 of the volume changer(s) 500, 600. The sensor(s) 109, 216, 217, 218, 316, 318, 524, 632 700, 800 can generate the sensor data 902, 904, 06, 907, 908 during the depressurization of the sample fluid and/or after the sample fluid has been depressurized.

[0270] The example downhole tool controller(s) 1 18, 401 , 501 , 630 and/or the example surface processor 1 12 can access the sensor data 902, 904, 906, 907, 908 generated by the sensor(s) 109, 216, 217, 218, 316, 318, 700, 800 via the tool bus 1 14 and the telemetry system 1 1 1 of FIGS. 1 and 9. In some examples, the data analyzer 909 of the example fluid analyzer 120 of the downhole tool controller 1 18 of FIGS. 1-3 and 9 processes the sensor data 902, 904, 906, 907, 908 by, for example, filtering the sensor data.

[0271] The example method of FIG. 13 includes analyzing the sensor data based on one or more rule(s) (block 1316). In the example of FIG. 13, the rule(s) can include predefined rules such as a fluid property thresholds, algorithms, etc. stored in and/or implemented by the downhole tool controller(s) and/or the surface processor(s). For example, the database 900 of the fluid analyzer 120 of FIGS. 1-3 and 9 stores rule(s) 916, which can be predefined rule(s) received from the surface. The rules manager 914 analyzes the sensor data 902, 904, 906, 907, 908 based on the rule(s) 916 (e.g., the algorithms). The rules manger 914 generates one or more analysis results 922 based on the rule(s) 916 and the sensor data 902, 904, 906, 907, 908, which can include, for example, bubble point pressure, dew point pressure, fluid compressibility, fluid density, sample fluid volume over time, etc. In some examples, the report generator 924 of the fluid analyzer 120 generates one or more phase diagrams 926 (e.g., the phase diagrams of FIGS. 10-12) based on the analysis result(s) 922. The analysis result(s) 922 and/or the phase diagram(s) 926 can be transmitted to the surface processor 1 12 via the telemetry system 1 11 .

[0272] In other examples, the sensor data 902, 904, 906, 907, 908 is transmitted to the surface processor 1 12 and the surface processor 1 12 performs the analysis of the sensor data based on rule(s) stored in the surface processor 1 12. In some examples, the downhole tool controller(s) 1 18, 401 , 501 , 630 and the surface processor 1 12 analyze the sensor data 902, 904, 906, 907, 908. In some examples, the rule(s) 916 include user input(s) 912 received from the surface.

[0273] The example method 1300 includes a decision of whether to analyze the sample fluid over one or more measurement cycles, or cycle(s) in which the sample fluid is depressurized and pressurized via the volume changer(s) (block 1318). In the example of FIG. 13, the decision of whether to analyze the sample fluid over one or more measurement cycles can be made by one or more downhole tool controller(s) and/or one or more surface processor(s).

[0274] If a decision is made to analyze the sample fluid over one or more measurement cycles, the example method 1300 includes activating the volume changer(s) to selectively pressurize and depressurize the sample fluid (block 1320). For example, the volume changer(s) 212, 312, 400, 500, 600 can pressurize the sample fluid via the volume changer(s) driver(s) 214, 410, 510, 628 (e.g., the piston(s) and/or other means (e.g., a pump). Sensor data can be generated during depressurization of the sample fluid, after depressurization of the sample fluid is complete, during pressurization of the sample fluid, and/or after pressurization of the sample fluid is complete. The sensor data can be analyzed for the one or more measurement cycles as discussed above based on rule(s) and/or algorithm(s) (e.g. blocks 1314, 1316). [0275] When a decision is made indicating that the analysis of the sample fluid is complete, the example method 1300 includes activating the control valve(s) to release the sample fluid (block 1322). For example, the fluid analyzer 120 can instruct the control valve(s) 108, 1 10, 204, 208, 306, 308 of the sample platform(s) 106, 200, 300 (e.g., via the communicator 910) to open, thereby allowing the flow of the formation fluid through the sample platform(s) and the production tubing 102 to resume.

[0276] The example method 1300 includes a decision of whether to collect additional sample fluid at the sample platform(s) (block 1324). In examples where the volume changer(s) include the sample container(s) 500, 600 of FIGS. 5 and 6 that enable sample fluid volume to be monitored over time, the fluid analyzer 120 of the downhole tool controller 120 and/or the surface processor 1 12 may evaluate the sample fluid volume to determine if the sample fluid has been properly captured and/or to determine if the sampling flow rate at the sample container(s) 500, 600 should be adjusted. In such examples, a decision may be made to collect additional sample fluid via the sample platform(s).

[0277] Thus, the example method 1300 of FIG. 13 provides for PV and/or PVT analyses to be performed on sample fluid in a downhole environment. In some examples, the PV and/or PVT analyses are automatically perfumed by downhole tool controller(s). The example method 1300 ends when there is no further sensor data for analysis (block 1324).

[0278] The flowchart of FIG. 13 is representative of an example method that may be used to implement the example system 100 of FIGS. 1-9. In this example, the method may be implemented using machine readable instructions comprising a program for execution by one or more processors such as the processor 1612 shown in the example processor platform 1600 discussed below in connection with FIG. 16. The program may be embodied in software stored on a non-transitory computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1612, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1612 and/or embodied in firmware or dedicated hardware. Further, although the example program is described with reference to the flowchart illustrated in FIG. 13, many other methods of implementing the example system 100 and/or components thereof may alternatively be used. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, or combined. Additionally or alternatively, any or all of the blocks may be implemented by one or more hardware circuits (e.g., discrete and/or integrated analog and/or digital circuitry, a Field Programmable Gate Array (FPGA), an Application Specific Integrated circuit (ASIC), a comparator, an operational- amplifier (op-amp), a logic circuit, etc.) structured to perform the corresponding operation without executing software or firmware

[0279] As disclosed herein in connection with FIGS. 5 and 6, in some examples, the sample containers enable a volume of sample fluid in the sample container(s) to be monitored over time based on pressure measurements for a compressible fluid (e.g., a gas) disposed in a dump chamber of the sample container(s). The use of pressure measurements for a compressible gas in a sample container is not limited to determining sample fluid volumes for purposes of PV and/or PVT analyses. Rather, the compressible fluid pressure analysis disclosed above can be used to monitor a position of a piston in, for example, a hydraulic device.

[0280] Monitoring a position of a piston in a downhole environment can be difficult due to, for example constraints with respect to a size of the hydraulic device and/or the piston as well as downhole conditions with respect to pressure, temperature, etc. In examples disclosed herein, a pressure sensor can be disposed in a chamber of a hydraulic device including a compressible fluid that is closed by a position. Pressure measurements generated by the pressure sensor can be used to determine positions of the piston. The piston position measurements can be used to control one or more downhole tools, such as valves that are hydraulically actuated via the piston.

[0281] For example, a moveable piston can be disposed in a chamber (e.g., a dump chamber) including a compressible fluid such as a gas. The piston includes a seal such that a quantity of gas in the chamber remains substantially constant. Movement of the piston along, for example, the Z axis causes a volume of the chamber to change such that a volume of the chamber Vc _h am _b er is a function of piston position Zpiston. The chamber volume Vc _h am _b er can be expressed as: [0282] Vchamber — k(Zpiston), Where Zpiston — k ^~ ^ (V Chamber), Where k IS based OP 3 relationship (e.g., a substantially linear relationship) between piston position end chamber volume defined by, for example, a geometry of the chamber (Equation 26).

[0283] The pressure end temperature of the compressible fluid in the chamber can be monitored using a pressure gauge ss disclosed above with respect to the example sample cont3iner(s) 500, 600 of FIGS. 5 end 6. Based on measurements generated by the pressure gauge for the compressible gas in the chamber, the chamber volume c _hamber csn be determined using, for example, Equations 5-1 1 above. The piston position Zpisto _n csn be determined based on the relationship with chamber volume Vchamber as defined by Equation 26, above.

[0284] FIG. 14 illustrates an example downhole tool control system 1400 for monitoring a position of a downhole tool and controlling the downhole tool based on piston positon measurements. One or more components of the example system 1400 can be implemented in a wellbore. The example system 1400 includes a downhole tool 1401 including a piston 1402 disposed in a piston chamber 1404. The piston 1402 can include a cylindrical piston, an annular hollow piston, etc. The example downhole tool 1401 includes a hydraulic accumulator 1406 that contains a volume of hydraulic fluid 1407 at wellbore or annulus pressure PH. The example downhole tool 1401 includes a dump chamber 1408 including a compressible fluid at low pressure P _Dump (e.g., atmospheric pressure). The compressible fluid can include a gas such as air.

[0285] The example piston 1402 is moveable along, for example, a z axis as represented by the arrow 1409 of FIG. 14. As illustrated in FIG. 14, the example piston 1402 defines three portions have respective volumes: a first portion 1410 having a first volume Vi associated with a first cross-sectional surface Sr, a second portion 1412 having a second volume Vi associated with a second cross-sectional surface S2, where the first cross-sectional surface Si is greater than the second cross- sectional surface S2; and a third portion 1414 having a third volume Veias associated with a third cross-section surface Se _as . [0286] In the example of FIG. 14, the first portion 1410 is coupled to the hydraulic accumulator 1406 or the dump chamber 1408 via a hydraulic control circuit 1416 of the downhole tool 1401. The second portion 1412 is coupled to the hydraulic accumulator 1406 via the hydraulic control circuit 1406. The hydraulic control circuit 1406 of FIG. 14 includes a first hydraulic valve 1418 and a second hydraulic valve 1420. In the example of FIG. 4, the hydraulic valves 1418, 1420 are actuated by the piston 1402.

[0287] The third portion 1414 of the piston chamber 1404 is a closed portion including a fixed quantity of compressible fluid 1415 (e.g., gas) at a low pressure Ps _/as , where Ps,- _as is less than PH (e.g., Ps/ _as << PH). Also, the volume I of the third portion 1414 is directly proportional to a position of the piston 1402. In the example of FIG. 14, one or more sensors 1422 are disposed in or operatively coupled to the third portion 1414. The sensor(s) 1422 can include a pressure sensor to monitor the pressure Ps _/as and temperature Teias of the compressible fluid 1415 in the third portion 1414.

[0288] In the example of FIG. 14, the hydraulic valves 1418, 1420 of the hydraulic control circuit 1406 and the sensor(s) 1422 of the third portion 1414 are communicatively coupled to a tool bus 1424, as represented by arrows 1426 in FIG. 14. The tool bus 1424 is communicatively coupled to a downhole-to-surface telemetry system 1428 via a downhole tool controller 1430 (e.g., a processor). The telemetry system 1428 is communicatively coupled to a surface processor 1432. The telemetry system 1428 and/or the tool bus 1424 can provide for wireline and/or wireless based connections. The example system 1400 of FIG. 14 can include additional downhole tool controllers 1430 and/or surface processors 1432.

[0289] In the example of FIG. 14, one or more instructions can be delivered from the surface processor 1432 to the valves 1418, 1420 of the hydraulic control circuit 1416 via the telemetry system 1428, the tool controller 1430, and the tool bus 1424. The instructions can include, for example, instructions for the valves 1418, 1420 to selectively open or close to control a flow of, for example, the hydraulic fluid 1407 from the hydraulic actuator 1406. [0290] In other examples, the instruction(s) for the valves 1418, 1420 of the hydraulic control circuit 1416 are generated by the tool controller 1430 and delivered by the tool controller 1430 via the tool bus 1424. The example tool controller 1430 of FIG. 14 includes a piston position analyzer 1434. As disclosed herein, the piston position analyzer 1434 can generate one or more instructions to control the valves 1418, 1420 downhole. The piston position analyzer 1434 can generate the instructions based on one or more commands received from the surface (e.g., via the surface processor 1432 and the telemetry system 1428 of FIG. 14), another downhole device (e.g., another downhole controller), and/or based on analyses performed by the piston position analyzer 1434.

[0291] In the example of FIG. 14, the sensor(s) 1422 associated with the third portion 1414 of the piston chamber 1404 are communicatively coupled to the tool bus 1424, as represented by arrow 1435 in FIG. 14. The sensor(s) 422 are communicatively to the downhole tool controller 1430 and the surface processor 1432 via the tool bus 1424 and the telemetry system 1428. In the example of FIG. 14, data collected by the sensor(s) 1422 is transmitted to the downhole tool controller 1430 and/or the surface processor 1432 via the tool bus 1424 and the telemetry system 1428.

[0292] The example piston positon analyzer 1434 of FIG. 14 includes a database 1436. The database 1436 stores sensor data 1437 generated by the sensor(s) 1422, such as gas pressure and gas temperature for the compressible fluid 1415 in the third portion 1414 of the piston chamber 1404.

[0293] The example piston positon analyzer 1434 of FIG. 14 includes a data analyzer 1438. The example data analyzer 1438 performs one or more data processing techniques such as converting the signal data 1437 from analog to digital data, filtering the data, removing noise from the signal data, compressing the data, etc. The processed data can be stored in the database 1436.

[0294] The example piston positon analyzer 1434 of FIG. 14 includes a communicator 1440. The communicator 1440 generates one or more instructions to enable transmission of the sensor data 1437 (e.g., the processed data) between the tool controller 1430 and the surface processor 1432 via the downhole-to-surface bi- directional telemetry system 1428 of FIG. 1.

[0295] The example communicator 1440 can also receive instructions from the surface processor 1432 via the telemetry system 1428. An operator can provide one or more user inputs 1442 via the surface processor 1432 with respect to, for example, a duration of time that the sensor(s) 422 should collect data. The user input(s) 1442 (e.g., instructions or commands) are transmitted downhole via the telemetry system 1428 and received by the communicator 1440 of the piston positon analyzer 1434. In some examples, the user input(s) 1442 are stored in the database 1436.

[0296] The example piston positon analyzer 1434 of FIG. 14 includes a rules manager 1444. The rules manager 1444 applies one or more rules 1446 to determine piston positon. The rule(s) 1446 can be stored in the database 1434.

[0297] In the example of FIG. 14, a force Fpiston applied on the piston 1402 can be determined based on the following equation:

[0298] Fpiston = Pi*Si - P2* S^Peias* Seias, where Pi is pressure PH of the hydraulic accumulator 1406 or PDump of the dump chamber 1408 depending on the coupling of the first portion 1410 via the hydraulic circuit and P ₂ is PH of the hydraulic accumulator 1406 (Equation 27).

[0299] The example rules manager 1444 determines the volume of gas IW in the third portion 1414 based on the gas pressure Peias and the gas temperature 7W of the compressible fluid 1415 in the third portion 1414 of the piston chamber 1404. For example, when the first portion 1410 is coupled to the hydraulic accumulator 1406, Pi = Pnand the piston 1402 moves in the Z+ direction. The movement of the piston 1402 in the Z+ direction reduces the volume IW of the third portion 1414 and, thus, cause an increase in the pressure Ps _/as . Conversely, when the first portion 1410 is coupled to the dump chamber 1408, Pi = PDump and the piston 1402 moves in the Z- direction. The movement of the piston 1402 in the Z- direction increases the volume IW of the third portion 1414 and, thus, cause an decrease in the pressure Ps _/as . The example rules manager 1444 determines the position Zpiston of the piston 1402 based on the gas volume I as defined by Equation 26, above (e.g., Zpiston = /c ¹ (Veias)). [0300] In the example of FIG. 14, the position of the piston 1402 can be used to determine and/or control a status of the first valve 1418 or the second valve 1420, such as whether the valve is open, closed, or in an intermediate position. Based on the determination of the position of the piston 1402, the rules manager 1448 can automatically generate one or more valve control instructions 1448 to control the valve(s) 1418, 1420. For example, the rules manager 1446 can use the piston position as an input when applying algorithms (e.g., rule 1446) to control the vavle(s) 1418, 1420.

[0301] The rules manager 1446 can monitor and/or control the valve(s) 1418, 1420 based on the position of the piston 1402 with respect to an on-position of the valve(s) 1418, 1420 or an off-position of the valve(s) 1418, 1420. In some examples, the valve(s) 1418, 1420 include downhole chokes having intermediate positions between the fully open and fully closed positions to provide for variable flow. In such examples, the rules manager 1446 can monitor and/or control the intermediate positions of the valve(s) 1418, 1420. The valve control instruction(s) 1448 can be transmitted by communicator 1440 of the piston position analyzer 1434 to the hydraulic circuit 1416.

[0302] In other examples, the surface processor 1432 determines the position of the piston 1402 based on the sensor data 1437 generated by the sensor(s) 1422 and transmitted to the surface via the telemetry system 1428. In such examples, the valve control instruction(s) 1448 can be generated at the surface processor 1432 and transmitted downhole. In some examples, the piston position analyzer 1434 determines the position position downhole and transmits the results to the surface processor 1432, where an operator can determine the valve control instruction(s) 1448 based on the downhole analysis.

[0303] While an example manner of implementing the example piston position analyzer 1434 is illustrated in FIG. 14, one or more of the elements, processes and/or devices illustrated in FIG. 14 may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way. Further, the example database 1436, the example data analyzer 1438, the example communicator 1440, the example rules manager 1444, and/or, more generally, the example piston position analyzer 1434 of FIG. 14 may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware. Thus, for example, any of the example database 1436, the example data analyzer 1438, the example communicator 1440, the example rules manager 1444, and/or, more generally, the example piston position analyzer 1434 of FIG. 14 could be

implemented by one or more analog or digital circuit(s), logic circuits, programmable processor(s), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)) and/or field programmable logic device(s) (FPLD(s)). When reading any of the apparatus or system claims of this patent to cover a purely software and/or firmware implementation, at least one of the example database 1436, the example data analyzer 1438, the example communicator 1440, the example rules manager 1444, and/or, more generally, the example piston position analyzer 1434 of FIG. 14 is/are hereby expressly defined to include a non-transitory computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a compact disk (CD), a Blu-ray disk, etc. including the software and/or firmware. Further still, the example piston position analyzer 1434 of FIG. 14 may include one or more elements, processes and/or devices in addition to, or instead of, those illustrated in FIG. 14, and/or may include more than one of any or all of the illustrated elements, processes and devices.

[0304] FIG. 15 illustrates a flowchart representative of an example method 1500 that can be implemented to determine position of a piston of downhole tool based on sensor data generated downhole from a compressible fluid. The method 1500 of FIG. 15 can be implemented by the example system 1400 of FIG. 14, including, for example, the example piston positon analyzer 1434 of the downhole tool controller 1430 and/or the surface processor 1432. Although the example method 1500 of FIG. 15 is discussed in connection with the downhole tool 1401 of FIG. 14, the example method 1500 can be implemented in connection with other downhole tools (e.g., the sample container(s) 500, 600 of FIGS. 5 and 6).

[0305] The example method 1500 begins with communicatively coupling a downhole tool including a compressible fluid and a piston to a downhole-to-surface telemetry system (block 1502). For example, the downhole tool 1401 of FIG. 14 including the hydraulic control circuit 1416, the valve(s) 1418, 1420, and the piston 1402, can be communicatively coupled to one or more controllers, such as the downhole tool controller 1430 and/or the surface processor 1432 via the tool bus 1424 and the telemetry system 1428 of FIG. 14. In the example hydraulic control circuit 1416 of FIG. 14, the piston 1402 is disposed in the piston chamber 1404, including the compressible fluid 1415. The communicative coupling between the hydraulic control circuit 1416 and the telemetry system 1428 can be established via one or more wireless connections, wireline connections, or a combination of wireless and wireline connections.

[0306] The example method 1500 includes communicatively coupling one or more sensors to a downhole-to surface telemetry system (block 1504). For example, the third portion 1414 of the piston chamber 1404 includes sensors such as the pressure sensor 1422 to measure a pressure and temperature of the compressible fluid 1415. The sensor(s) 1422 are communicatively coupled to the downhole tool controller 1430 and, thus, the telemetry system 1428 via the tool bus 1424. The communicative coupling between the sensor(s) 1422 and the telemetry system 1428 can be established via one or more wireless connections, wireline connections, or a combination of wireless and wireline connections

[0307] The example method 1500 of FIG. 15 includes accessing sensor data generated by the sensor(s) for the compressible fluid of the downhole tool (block 1506). In the example of FIG. 15, the sensor data can be accessed by one or more downhole tool controller(s) and/or one or more surface processor(s). For example, the sensor(s) 1422 of the third portion 1414 of the piston chamber 1404 generate pressure and temperature data 1437 for the compressible fluid 1415 disposed in the third portion 1414, for example, before, during and/or after movement of the piston 1402. The example downhole tool controller 1430 and/or the example surface processor 1432 can access the sensor data 1437 generated by the sensor(s) 1422 via the tool bus 1424 and the telemetry system 1428 of FIG. 14. In some examples, the data analyzer 1438 of the example piston position analyzer 1434 of the downhole tool controller 1430 of FIG. 14 processes the sensor data 1437 by, for example, filtering the sensor data. [0308] The example method of FIG. 15 includes analyzing the sensor data based on one or more rule(s) to determine a position of the piston of the downhole tool (block 1508). For example, the database 1436 of the piston position analyzer 1434 of FIG. 14 stores rule(s) 1446 with respect to analyzing the relationship between the pressure of the compressible fluid, the temperature of the compressible fluid, and the volume of the chamber holding the compressible fluid and changes with respect to the pressure, temperature, and/or volume variables. The rule(s) can also define the relationship between chamber volume and piston position (e.g., Equation 26, above). The rules manager 1444 analyzes the sensor data 1437 based on the rule(s) 1446 (e.g., the algorithms) to determine the piston position.

[0309] The example method 1500 of FIG. 15 includes identifying a status of one or more components of the downhole tool based on the piston position (block 1510). For example, based on the position of the piston 1402, the example rules manager 1444 of FIG. 14 can determine a status of the first and/or second valve(s) 1418, 1420 the hydraulic control circuit 1416. The rules manager 1444 can determine if, for example, the valve(s) 1418, 1420 are open, closed, or in an intermediate position.

[0310] The example method 1500 includes a decision of whether to adjust the one or more tool components based on the status of the tool component(s) (block 1512). If a decision is made to adjust the tool component(s), the example method 1500 includes adjusting the tool component(s) (block 1514). For example, the rules manager 1444 of the piston position analyzer 1434 of FIG. 14 can generate the valve control instruction(s) 1448 to adjust the state of the valve(s) 1418, 1420 between open, closed, or intermediate positions based on the analysis of the positon of the piston 1402. In other examples, the valve control instruction(s) 1448 are generated at the surface processor 1432.

[0311] Thus, the example method 1500 of FIG. 15 provides for determination of piston position based on changes pressure data for a compressible fluid and corresponding relationships between the pressure, volume, and piston position. The example method 1500 ends when there is no further pressure sensor data for analysis (block 1516). [0312] The flowchart of FIG. 15 is representative of an example method that may be used to implement the example system 1400 of FIG. 14. In this example, the method may be implemented using machine readable instructions comprising a program for execution by one or more processors such as the processor 1712 shown in the example processor platform 1700 discussed below in connection with FIG. 1700. The program may be embodied in software stored on a non-transitory computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1712, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1712 and/or embodied in firmware or dedicated hardware. Further, although the example program is described with reference to the flowchart illustrated in FIG. 15, many other methods of implementing the example system 1400 and/or components thereof may alternatively be used. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, or combined. Additionally or alternatively, any or all of the blocks may be implemented by one or more hardware circuits (e.g., discrete and/or integrated analog and/or digital circuitry, a Field Programmable Gate Array (FPGA), an Application Specific Integrated circuit (ASIC), a comparator, an operational- amplifier (op-amp), a logic circuit, etc.) structured to perform the corresponding operation without executing software or firmware

[0313] As mentioned above, the example processes of FIGS. 13 and 15 may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and to exclude transmission media. “Including” and“comprising” (and all forms and tenses thereof) are used herein to be open ended terms. Thus, whenever a claim lists anything following any form of“include” or“comprise” (e.g., comprises, includes, comprising, including, etc.), it is to be understood that additional elements, terms, etc. may be present without falling outside the scope of the corresponding claim. As used herein, when the phrase "at least" is used as the transition term in a preamble of a claim, it is open-ended in the same manner as the term "comprising" and “including” are open ended.

[0314] FIG. 16 is a block diagram of an example processor platform 1600 capable of executing instructions to implement the method of FIG. 13 to implement the fluid analyzer 120 of FIGS. 1-3 and 9. The processor platform 1600 can be, for example, a server, a personal computer, a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad™), a personal digital assistant (PDA), an Internet appliance, or any other type of computing device.

[0315] The processor platform 1600 of the illustrated example includes a processor 1612. The processor 1612 of the illustrated example is hardware. For example, the processor 1612 can be implemented by one or more integrated circuits, logic circuits, microprocessors or controllers from any desired family or manufacturer. The hardware processor may be a semiconductor based (e.g., silicon based) device. In this example, the processor implements the fluid analyzer 120 and its components (e.g., the example data analyzer 909, the example

communicator 910, the example rules manager 914, the example report generator 924). The processor 1622 can include, for example, the downhole tool controller(s) 1 18, 401 , 501 , 630 and/or the surface processor(s) 1 12 of FIGS. 1-6 and 9.

[0316] The processor 1612 of the illustrated example includes a local memory 1613 (e.g., a cache). The processor 1612 of the illustrated example is in

communication with a main memory including a volatile memory 1614 and a non- volatile memory 1616 via a bus 1618. The volatile memory 1614 may be

implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device. The non-volatile memory 1616 may be implemented by flash memory and/or any other desired type of memory device. Access to the main memory 1614, 1616 is controlled by a memory controller. The database 900 of the fluid analyzer 120 may be implemented by the main memory 1614, 1616.

[0317] The processor platform 1600 of the illustrated example also includes an interface circuit 1620. The interface circuit 1620 may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.

[0318] In the illustrated example, one or more input devices 1622 are connected to the interface circuit 1620. The input device(s) 1622 permit(s) a user to enter data and/or commands into the processor 1612. The input device(s) can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, isopoint and/or a voice recognition system.

[0319] One or more output devices 1624 are also connected to the interface circuit 1620 of the illustrated example. The output devices 1624 can be

implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display, a cathode ray tube display (CRT), a touchscreen, a tactile output device, a printer and/or speakers).

The interface circuit 1620 of the illustrated example, thus, typically includes a graphics driver card, a graphics driver chip and/or a graphics driver processor.

[0320] The interface circuit 1620 of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1626 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).

[0321] The processor platform 1600 of the illustrated example also includes one or more mass storage devices 1628 for storing software and/or data. Examples of such mass storage devices 1628 include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives.

[0322] Coded instructions 1632 to implement the method of FIG. 13 may be stored in the mass storage device 1628, in the volatile memory 1614, in the non- volatile memory 1616, and/or on a removable tangible computer readable storage medium such as a CD or DVD.

[0323] FIG. 17 is a block diagram of an example processor platform 1700 capable of executing instructions to implement the method of FIG. 15 to implement the piston position analyzer 1434 of FIG. 14. The processor platform 1700 can be, for example, a server, a personal computer, a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad™), a personal digital assistant (PDA), an Internet appliance, or any other type of computing device.

[0324] The processor platform 1700 of the illustrated example includes a processor 1712. The processor 1712 of the illustrated example is hardware. For example, the processor 1712 can be implemented by one or more integrated circuits, logic circuits, microprocessors or controllers from any desired family or manufacturer. The hardware processor may be a semiconductor based (e.g., silicon based) device. In this example, the processor implements the piston position analyzer 1432 and its components (e.g., the example data analyzer 1438, the example communicator 1440, the example rules manager 1444). The processor

1712 can include, for example, the downhole tool controller 1430 and/or the surface processor(s) 1432 of FIG. 14.

[0325] The processor 1712 of the illustrated example includes a local memory

1713 (e.g., a cache). The processor 1712 of the illustrated example is in

communication with a main memory including a volatile memory 1714 and a non- volatile memory 1716 via a bus 1718. The volatile memory 1714 may be

implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device. The non-volatile memory 1716 may be implemented by flash memory and/or any other desired type of memory device. Access to the main memory 1714, 1716 is controlled by a memory controller. The database 1436 of the piston position analyzer 1434 may be implemented by the main memory 1714, 1716.

[0326] The processor platform 1700 of the illustrated example also includes an interface circuit 1720. The interface circuit 1720 may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.

[0327] In the illustrated example, one or more input devices 1722 are connected to the interface circuit 1720. The input device(s) 1722 permit(s) a user to enter data and/or commands into the processor 1712. The input device(s) can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, isopoint and/or a voice recognition system.

[0328] One or more output devices 1724 are also connected to the interface circuit 1720 of the illustrated example. The output devices 1724 can be

implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display, a cathode ray tube display (CRT), a touchscreen, a tactile output device, a printer and/or speakers).

The interface circuit 1720 of the illustrated example, thus, typically includes a graphics driver card, a graphics driver chip and/or a graphics driver processor.

[0329] The interface circuit 1720 of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1726 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).

[0330] The processor platform 1700 of the illustrated example also includes one or more mass storage devices 1728 for storing software and/or data. Examples of such mass storage devices 1728 include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives.

[0331] Coded instructions 1732 to implement the method of FIG. 15 may be stored in the mass storage device 1728, in the volatile memory 1714, in the non- volatile memory 1716, and/or on a removable tangible computer readable storage medium such as a CD or DVD.

[0332] From the foregoing, it will be appreciated that above-disclosed apparatus, systems and methods provide for pressure-volume (PV) and/or pressure-volume- temperature (PVT) analyses to performed downhole based on sample formation fluid collected via sample platforms disposed at one or more downhole depths. In examples disclosed here, the sample fluid can be selectively depressurized or pressurized via sampling devices associated with the sample platforms that provide for low-shocks sampling. In examples disclosed herein, the sampling device(s) are coupled to or integrated with production tubing such that fluid flowing through the production tubing flows through and can by captured by the sampling device(s). In examples disclosed herein, sensor data can be generated during depressurization and/or pressurization of the sample fluid analyzed over one or more measurement cycles to determine, for example, bubble point pressure, fluid density, fluid compressibility, etc. The results of the analyses can be used to, for example, characterize the formation fluid, generate reservoir models, etc. in situ and without requiring the sample fluid to be brought to the surface. Thus, examples disclosed herein provide for increased accuracy in the PV and/or PVT analyses as compared to analyses performed at the surface, where characteristics of the sample fluid often change by the time the analyses are performed.

[0333] Some examples disclosed herein provide for sample fluid volume to be measured over time and/or a position of a piston to be determined based on pressure data for a compressible fluid disposed in a chamber (e.g., a dump chamber in a sampling container or a piston chamber of a hydraulic device). In some such examples, the sample fluid volume can be monitored over time to, for example, determine fluid density or fluid compressibility, to control the sampling flow rate, verity that the sample has been properly captured, etc. In other such examples, the position of the piston determined from the compressible fluid pressure data can be can be used to control to one or more downhole tools, such as downhole valves.

[0334] An example apparatus includes a sample platform coupled to production tubing disposed in a wellbore and a first chamber defined by the sample platform. The first chamber is to capture a fluid flowing through the production tubing. The example apparatus includes a second chamber coupled to the sample platform. The example apparatus includes a first sensor coupled to the sample platform and a controller. The sample platform, the second chamber, and the first sensor are to be communicatively coupled to the controller. The controller is to selectively instruct the second chamber to one of depressurize or pressurize the fluid, the first sensor to generate fluid data for the fluid during the depressurization or the pressurization of the fluid and conduct a pressure-volume analysis for the fluid based on the fluid data.

[0335] In some examples, the controller is disposed in the wellbore. In some such examples, the controller is to transmit a result of the pressure-volume analysis to a second controller disposed outside the wellbore and receive, from the second controller, a user input to adjust a parameter of the pressure-volume analysis.

[0336] In some examples, the controller is to determine one or more of a bubble point pressure for the fluid, a dew point pressure for the fluid, a fluid density value, or a fluid compressibility value based on the pressure-volume analysis.

[0337] In some examples, the second chamber includes a trigger and the controller is to activate the trigger to cause the second chamber to depressurize the fluid.

[0338] In some examples, the apparatus further includes a phase nucleation device disposed in the sample platform and the first sensor is to be disposed proximate to the phase nucleation device.

[0339] In some examples, the second chamber includes first portion to receive the fluid and a second portion to hold a gas. In such examples, the apparatus further includes a second sensor disposed in the second chamber and the controller is to determine a volume of the fluid in the second chamber based on pressure data generated by the second sensor. [0340] In some examples, the controller is to selectively instruct the first chamber to release the fluid.

[0341] An example apparatus includes a housing having a first end and a second end, the first end and the second end to be aligned with a flow path of fluid in a wellbore. The example apparatus includes a first chamber defined by the housing. The first chamber is to collect the fluid. The example apparatus includes a second chamber coupled to the housing and means for selectively depressurizing or pressurizing the fluid via the second chamber.

[0342] In some examples, the means for selectively pressurizing or depressurizing the fluid includes a piston.

[0343] In some examples, the second chamber includes a flow restrictor having a first seal and the means for selectively depressurizing or pressurizing the fluid include a rod having a second seal to selectively disengage or engage the first seal.

[0344] In some examples, the second chamber is disposed in the first chamber.

[0345] In some examples, the first end and the second end are coupled to production tubing.

[0346] In some examples, the apparatus further includes a first valve disposed at the first end and a second valve disposed at the second end.

[0347] An example method includes directing, by executing an instruction with a processor, a sample platform to capture fluid flowing through production tubing in a wellbore. The sample platform is aligned with the production tubing. The example method includes directing, by executing an instruction with a processor, a sample container coupled to the sample platform to depressurize the fluid captured by the sample platform. The example method includes accessing, by executing an instruction with a processor, fluid property data for the depressurized fluid. The example method includes directing, by executing an instruction with a processor, the sample platform to release the fluid. [0348] In some examples, the method further includes activating a phase nucleation device disposed in the sample platform, the fluid property data to be generated during activation of the phase nucleation device.

[0349] In some examples, the method further includes generating a fluid phase diagram based on the fluid property data.

[0350] In some examples, the method further includes instructing the sample container to pressurize the fluid.

[0351] In some examples, directing the sample platform to capture the fluid includes instructing a valve of the sample platform to close.

[0352] In some examples, the method further includes detecting one or more of a phase change or a presence of asphaltene in the fluid based on the fluid property data.

[0353] In the specification and appended claims: the terms “connect,” “connection,”“connected,”“connecting,” and/or other variations thereof are used to mean“in direct connection with” or“in connection with via one or more elements;” and the term“set” and/or variations thereof is used to mean“one element” or“more than one element.” Further, the terms“couple,”“coupling,”“coupled,” and“coupled to” and/or other variation thereof are used to mean“directly coupled together” or“coupled together via one or more elements.”

[0354] The foregoing outlines features of several embodiments so that those skilled in the art may better understand 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 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.

[0355] Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.