Methods and apparatus to determine phase-change pressures

Example methods and apparatus to determine phase-change pressures are disclosed. A disclosed example method includes capturing a fluid in a chamber, pressurizing the fluid at a plurality of pressures, measuring a plurality of transmittances of a signal through the fluid at respective ones of the plurality of pressures, computing a first magnitude of a first subset of the plurality of transmittances, computing a second magnitude of a second subset of the plurality of transmittances, comparing the first and second magnitudes to determine a phase-change pressure for the fluid.

BACKGROUND

Wellbores may be drilled to, for example, locate and produce hydrocarbons. During a drilling operation, it may be desirable to evaluate and/or measure properties of encountered formations, formation fluids and/or formation gasses. An example property is the phase-change pressure of a formation fluid, which may be a bubble point pressure, a dew point pressure and/or an asphaltene onset pressure depending on the type of fluid. In some cases, a drillstring is removed and a wireline tool deployed into the wellbore to test, evaluate and/or sample the formation(s), formation gas(ses) and/or formation fluid(s). In other cases, the drillstring may be provided with devices to test and/or sample the surrounding formation(s), formation gas(ses) and/or formation fluid(s) without having to remove the drillstring from the wellbore.

DETAILED DESCRIPTION

Certain examples are shown in the above-identified figures and described in detail below. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic for clarity and/or conciseness. It is to be understood that while the following disclosure provides many different embodiments or examples for implementing different features of various embodiments, other embodiments may be implemented and/or structural changes may be made without departing from the scope of this disclosure. Further, while specific examples of components and arrangements are described below these are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of clarity and does not in itself dictate a relationship between the various embodiments and/or example configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second elements are implemented in direct contact, and may also include embodiments in which other elements may be interposed between the first and second elements, such that the first and second elements need not be in direct contact.

Methods and apparatus for analyzing formation fluid(s) are disclosed herein. The methods and apparatus of the present disclosure may be used to determine phase-change pressures of fluid(s) extracted from a subterranean formation into which a well has been drilled. In some cases, the formation fluid(s) may be brought to the surface and analyzed in a laboratory. In other cases, the formation fluid(s) may be analyzed in situ using a drillstring and/or wireline fluid analysis tool lowered into the well. Example phase-change and/or phase-transition pressures include a bubble point (Pb) pressure, a dew point (Pd) pressure and/or an asphaltene onset pressure (AOP), depending on the type(s) of fluid(s) being analyzed. As used herein, the detection and/or identification of the onset of phase-change of a fluid refers to the identification of the time and/or the pressure during a systematic depressurization or reductions in the pressure of the fluid at which a phase-change of the fluid occurs. While certain examples are described using systematic depressurization of the fluid, the example methods and apparatus disclosed herein may, additionally or alternatively, be implemented using systematic pressurization or increases in the pressure of the fluid. Accordingly, throughout this disclosure references are made to systematic (de-)pressurization meaning that either a systematic pressurization or a systematic depressurization may be implemented.

In the present disclosure, fluid analysis tools may induce a prescribed rate of change of the pressure of a formation fluid trapped, captured and/or held in the fluid analysis tool. The fluid may be, for example, depressurized according to a predetermined pressure versus time profile. The fluid analysis tool may include a pressure changing device configured to controllably induce the prescribed pressure change. The phase-change pressure of the fluid may be determined using light scattering measured at a plurality of times during the depressurization of the fluid. During a first portion or phase of the depressurization of the fluid, the amount of light transmitted through the fluid may be uninterrupted (e.g., substantially unscattered), provided that the fluid remains in its single phase. That is, assuming the pressure of the fluid during this first portion or phase remains above the phase-change pressure. In contrast, when the pressure of the fluid reaches the phase-change pressure, gas bubbles, liquid droplets and/or asphaltene particles may emerge from the fluid and may begin scattering light. When the light passing through the fluid is scattered by the gas bubbles, liquid droplets and/or asphaltene particles, light transmittance through the fluid may be reduced. Detection of the reduction in light transmittance may be used to detect the onset of the phase-change. While the examples described herein utilize a scattering detector comprising a photo-detector to measure light transmittance (or conversely light scattering) through a fluid, the example methods and apparatus disclosed herein may be implemented using any number and/or type(s) of additional and/or alternative sensor(s) and/or detector(s) configured to measure scattering and/or transmittability of any number and/or type(s) of signals through a fluid. For example, an acoustic sensor may be implemented to detect gas bubbles, liquid droplets and/or asphaltene particles based on the scattering of an acoustic signal by any gas bubbles, liquid droplets and/or asphaltene particles present in the fluid. Another example sensor is an electrical resistivity sensor configured to measure a change in resistivity of the fluid in the presence or absence of gas bubbles, liquid droplets and/or asphaltene particles.

The methods and apparatus of the present disclosure may not require measuring a volume of the formation fluid to determine the phase-change pressure of the formation fluid. The foregoing may be advantageous when, for example, a determination of the formation fluid volume is difficult to obtain and/or is unknown. The determination of the formation fluid volume may be difficult to ascertain when the formation fluid is not sealed in a test volume, flowline and/or chamber, and/or if an enclosure containing the formation fluid is relatively compliant under pressure compared to the compressibility of the formation fluid. However, the volume of the formation fluid may optionally be estimated, measured and/or utilized within the scope of the present disclosure. Further, the examples described herein do not rely on, require and/or depend on a detectable transition in a pressure-versus-volume curve. As shown below, pressure-versus-volume data may be smooth at the phase-change pressure, making phase-change detection from pressure-versus-volume data unreliable and/or difficult.

FIG. 1depicts an example wellsite system according to one or more aspects of the present disclosure. The example wellsite ofFIG. 1may be situated onshore (as shown) or offshore. The example wellsite system may include a wireline assembly100, which may be configured to determine phase-change pressures of formation fluid(s) extracted from a subterranean formation F into which a wellbore102has been drilled.

The example wireline assembly100ofFIG. 1may be suspended in the wellbore102from the lower end of a multi-conductor cable104, which may be spooled on a winch (not shown) at the Earth's surface. At the surface, the cable104may be communicatively and/or electrically coupled to a control and data acquisition system106. The example control and data acquisition system106ofFIG. 1may include a controller106A having an interface configured to receive commands from a surface operator. The control and data acquisition system106may further include a processor106B configured to determine phase-change pressures of formation fluid(s) extracted from the subterranean formation F.

The example wireline assembly100ofFIG. 1may have an elongated body108and may include a telemetry module110and/or a formation tester114. Although the example telemetry module110ofFIG. 1is shown as being implemented separate from the example formation tester114, the telemetry module110may alternatively be implemented by the formation tester114. Further, additional and/or alternative components, modules and/or tools may also be implemented by the wireline assembly100.

The example formation tester114ofFIG. 1may include a selectively extendable fluid admitting assembly and/or probe116and/or a selectively extendable tool anchoring member118that may be arranged on opposite sides of the example body108. As shown, the fluid admitting assembly116may be configured to selectively seal off and/or isolate selected portions of the wall of the wellbore102and to fluidly couple components of the formation tester114such as, for example, a pump121, to the formation F. Thus, the formation tester114may be used to obtain fluid(s) from the formation F.

The example formation tester114ofFIG. 1may also include a fluid sensing unit120through which formation fluid(s) may flow. The example fluid sensing unit120, through which the obtained fluid(s) may flow, may be configured to measure properties of the fluid(s) extracted from the formation F. It should be appreciated that the fluid sensing unit120may include any combination of past, present and/or future-developed sensors within the scope of the present disclosure. The fluid(s) may thereafter be expelled through a port122into the wellbore102and/or the fluid(s) may be sent to one or more fluid collecting chambers disposed in a sample carrier module128. The fluid collecting chambers may receive and retain samples of the formation fluid(s) for subsequent retrieval and/or testing at the surface and/or at a testing facility and/or laboratory.

In the illustrated example ofFIG. 1, the example formation tester114implements a fluid isolation and analysis tool126that is fluidly coupled to the fluid admitting assembly116and the pump121. The example fluid isolation and analysis tool126ofFIG. 1may include a pressure changing device404(FIG. 4A) configured to controllably induce and/or affect a pressure change of a formation fluid(s) extracted from the subterranean formation F. The example fluid isolation and analysis tool126may also include a scattering detector444(FIG. 4A) configured to measure the amount of light that passes through the fluid(s). The fluid isolation and analysis tool126may further include one or more additional sensors that may be used to assist in the determination of phase-change pressures. Example additional sensors that may be implemented include, but are not limited to, a multi-channel spectrometer, a density/viscosity (DV) sensor, such as a DV rod, configured to measure fluid density and/or fluid viscosity, a pressure gauge, and/or a temperature gauge.

The example telemetry module110ofFIG. 1may comprise a downhole control system112communicatively coupled to the example control and data acquisition system106. In the illustrated example ofFIG. 1, the control and data acquisition system106and/or the downhole control system112may be configured to control the fluid admitting assembly116and/or the extraction of fluid(s) from the formation F by, for example, selecting a pumping rate of the pump121. The control and data acquisition system106and/or the downhole control system112may further be configured to direct the example fluid isolation and analysis tool126to induce or affect a targeted rate of change of the pressure of the formation fluid in the fluid isolation and analysis tool126, and/or to measure light transmittance of the fluid during the systematic pressure change(s).

The example control and data acquisition system106and/or the example downhole control system112ofFIG. 1may be further configured to analyze and/or process data obtained, for example, from the fluid sensing unit120and/or from other downhole sensors disposed in the example fluid isolation and analysis tool126. Such data may be stored and/or communicated to the surface for subsequent retrieval and/or analysis. In particular, a phase-change pressure of the formation fluid in the fluid isolation and analysis tool126may be determined using data collected by the scattering detector444during (de-)pressurization of the formation fluid.

As depicted inFIG. 1, the example wireline assembly100may include multiple downhole modules that are operatively connected together. Downhole tools often include several modules (i.e., sections of the wireline assembly100that perform different functions). Additionally, more than one downhole tool or component may be combined on the same wireline to accomplish multiple downhole tasks during the same wireline run. The modules are typically connected by field joints. For example, one module of a formation testing tool typically has one type of connector at its top end and a second type of connector at its bottom end. The top and bottom connectors are made to operatively mate with each other. By using modules and/or tools with similar arrangements of connectors, all of the modules and tools may be connected end-to-end to form the wireline assembly100. A field joint may provide an electrical connection, a hydraulic connection, and/or a flowline connection, depending on the requirements of the tools on the wireline. An electrical connection typically provides both power and communication capabilities.

In practice, the wireline tool assembly100may include several different components, some of which may include two or more modules (e.g., a sample module and a pumpout module of a formation testing tool). In this disclosure, the term “module” is used to describe any of the separate and/or individual tool modules that may be connected in the wireline assembly100. The term “module” refers to any part of the wireline assembly100, whether the module is part of a larger tool or a separate tool by itself. It is also noted that the term “wireline tool” is sometimes used in the art to describe the entire wireline assembly100, including all of the individual tools that make up the assembly. In this disclosure, the term “wireline assembly” is used to prevent any confusion with the individual tools that make up the wireline assembly (e.g., a coring tool, a formation testing tool, and a nuclear magnetic resonance (NMR) tool may all be included in a single wireline assembly).

FIG. 2depicts another example wellsite fluid analysis system according to one or more aspects of the present disclosure, which may be employed onshore (as shown) and/or offshore. In the example wellsite system ofFIG. 2, the example borehole102is formed in the subsurface formation F by rotary and/or directional drilling. In the illustrated example ofFIG. 2, a drillstring205is suspended within the example borehole102and has a bottom hole assembly (BHA)210having a drill bit215at its lower end. A surface system includes a platform and derrick assembly220positioned over the borehole102. The assembly220may include a rotary table221, a kelly222, a hook223and/or a rotary swivel224. The drillstring205may be rotated by the rotary table221, energized by means not shown, which engages the kelly222at the upper end of the drillstring205. The example drillstring205may be suspended from the hook223, which may be attached to a traveling block (not shown) and through the kelly222and the rotary swivel224, which permits rotation of the drillstring205relative to the hook223. Additionally or alternatively, a top drive system may be used.

In the example ofFIG. 2, the surface system may also include drilling fluid225, which is commonly referred to in the industry as mud, stored in a pit230formed at the wellsite. A pump235may deliver the drilling fluid225to the interior of the drillstring205via a port (not shown) in the swivel224, causing the drilling fluid225to flow downwardly through the drillstring205as indicated by the directional arrow240. The drilling fluid225may exit the drillstring205via water courses, nozzles, jets and/or ports in the drill bit215, and then circulate upwardly through the annulus region between the outside of the drillstring205and the wall of the borehole102, as indicated by the directional arrows241. The drilling fluid225may be used to lubricate the drill bit215and/or carry formation cuttings up to the surface, where the drilling fluid225may be cleaned and returned to the pit230for recirculation. The drilling fluid225may also be used to create a mudcake layer (not shown) on the walls of the borehole102. It should be noted that in some implementations, the drill bit215may be omitted and the bottom hole assembly210may be conveyed via tubing and/or pipe.

The example BHA210ofFIG. 2may include, among other things, any number and/or type(s) of downhole tools, such as any number and/or type(s) of logging-while-drilling (LWD) modules (one of which is designated at reference numeral250), and/or any number and/or type(s) of measuring-while-drilling (MWD) modules (one of which is designated at reference numeral255), a rotary-steerable system or mud motor260, and/or the example drill bit215. MWD typically refers to measuring the drill bit trajectory as well as wellbore temperature and pressure, while LWD refers to measuring formation and/or formation fluid parameters or properties, such as a resistivity, a porosity, a permeability, a viscosity, a density, a phase-change pressure, and a sonic velocity, among others. Real-time data, such as the formation pressure, allows the drilling company to make decisions about drilling mud weight and composition, as well as decisions about drilling rate and weight-on-bit during the drilling process. While LWD and MWD have different meanings to those of ordinary skill in the art, that distinction is not germane to this disclosure, and therefore this disclosure does not distinguish between the two terms. Furthermore, LWD and MWD need not be performed while the drill bit is actually cutting through the formation F. For example, LWD and MWD may occur during interruptions in the drilling process, such as when the drill bit215is briefly stopped to take measurements, after which drilling resumes. Measurements taken during intermittent breaks in drilling are still considered to be made “while-drilling” because they do not require the drill string to be tripped, that is, removed from the wellbore102.

The example LWD module250ofFIG. 2is housed in a special type of drill collar, as it is known in the art, and may contain any number and/or type(s) of logging tool(s), measurement tool(s), sensor(s), device(s), formation evaluation tool(s), fluid analysis tool(s), and/or fluid sampling device(s). For example, the LWD module250may be configured to measure light transmittance of a formation fluid while the fluid is systematically pressurized and/or depressurized to determine a phase-change pressure of the formation fluid. The LWD module250may include capabilities for measuring, processing, and/or storing information, as well as for communicating with the MWD module260and/or directly with surface equipment, such as the example logging and control computer106. While a single LWD module250is depicted inFIG. 2, it will also be understood that more than one LWD module may be implemented. The example LWD module250ofFIG. 2may include a processor470(FIG. 4A) configured to implement one or more aspects of the present disclosure.

The example MWD module255ofFIG. 2is also housed in a special type of drill collar and contains one or more devices for measuring characteristics of the drillstring205and/or the drill bit215. The example MWD tool255may also include an apparatus (not shown) for generating electrical power for use by the downhole system210. Example devices to generate electrical power include, but are not limited to, a mud turbine generator powered by the flow of the drilling fluid, and a battery system. Example measuring devices include, but are not limited to, a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick/slip measuring device, a direction measuring device, and an inclination measuring device. Additionally or alternatively, the MWD module255may include an annular pressure sensor, and/or a natural gamma ray sensor. The MWD module255may include capabilities for measuring, processing, and storing information, as well as for communicating with the logging and control unit106. For example, the MWD module255and the logging and control unit106may communicate information either way (i.e., uplink and downlink) using any past, present or future two-way telemetry system such as a mud-pulse telemetry system, a wired drillpipe telemetry system, an electromagnetic telemetry system and/or an acoustic telemetry system. While not shown inFIG. 2, the example control and data acquisition system106ofFIG. 2may include the example controller106A and/or the example processor106B discussed above in connection withFIG. 1.

FIG. 3depicts an example manner of implementing the example LWD module250ofFIG. 2. Because some elements of the example LWD module250ofFIG. 3are identical to those discussed above in connection withFIG. 1, the description of identical elements is not repeated here. Instead, identical elements are designated with identical reference numerals inFIGS. 1 and 3, and the interested reader is referred back to the descriptions presented above in connection withFIG. 1for a complete description of those like-numbered elements.

The example LWD module250ofFIG. 3may include a stabilizer having one or more blades305configured to engage a wall310of the wellbore102. The example LWD module250may also include one or more backup pistons, two of which are designated at reference numerals315and316, to assist in applying a force to push and/or move the LWD module250against the wall310of the wellbore102. Example blades305and backup pistons315and316are described in U.S. Pat. No. 7,114,562, which is hereby incorporated herein by reference in its entirety. However, any number and/or type(s) of additional and/or alternative blades and/or pistons may be used to implement the LWD module250.

The example LWD module250ofFIG. 3may include a fluid admitting assembly320, which may extend from the stabilizer blade305. The fluid admitting assembly320may be configured to selectively seal off or isolate selected portions of the wall310of the wellbore102to fluidly couple the LWD module250to an adjacent formation F. Once the fluid admitting assembly310fluidly couples to the adjacent formation F, various measurements may be conducted on the adjacent formation F and/or a fluid330drawn from the formation F. For example, a pressure parameter may be measured by performing a pretest.

While the wireline assembly100ofFIG. 1and the LWD module250ofFIG. 3are depicted having one fluid admitting assembly116,320, respectively, a plurality of fluid admitting assemblies may alternatively be provided on the wireline assembly100and/or the LWD module250. In particular, the fluid admitting assembly116ofFIG. 1and/or the fluid admitting assembly320ofFIG. 3may be implemented with a guarded and/or focused fluid admitting assembly, for example, as shown in U.S. Pat. No. 6,964,301, which is hereby incorporated by reference in its entirety. In such cases, the fluid isolation and analysis tool126may, for example, be fluidly coupled to a central inlet and/or port of the guarded or focused fluid admitting assembly116,320.

FIGS. 4A-Cdepict an example manner of implementing the example fluid isolation and analysis tool126ofFIGS. 1 and 3. While the example fluid isolation and analysis tool126ofFIGS. 4A-Cis described with reference to the example downhole tools100and250ofFIGS. 1-3, the example methods and apparatus disclosed herein to determine phase-change pressures may, additionally or alternatively, be implemented in a laboratory located at a wellsite and/or elsewhere.

The fluid isolation and analysis tool126ofFIG. 4Amay include the pressure changing device404, which may be configured to controllably induce and/or affect a systematic pressure change in a test chamber, volume, and/or flowline408based on at least one prescribed rate412. In other words, the example pressure changing device404ofFIGS. 4A-4Cmay be configured to induce or affect a targeted rate of change of the pressure of a fluid trapped and/or captured in the test flowline408according to the pressure rate profile412. The example pressure changing device404may include a sliding piston405configured to alter the pressure in the test flowline408. The example piston405may be affixed to a ram406, which is configured to reciprocate upon rotation of, for example, an electric motor416such as a stepper motor. For example, an output shaft (not shown) of the example motor416may be operatively coupled to a gear box (not shown) that engages the ram406to move the example piston405. As used herein, the fluid trapped and/or captured in the test flowline408includes fluid trapped and/or captured in the pressure changing device404.

The example fluid isolation and analysis tool126ofFIGS. 4A-4Cmay further include a controller420to induce pressure changes in the test flowline408based on fluid pressures measured in the test flowline408. For example, the example controller420ofFIG. 4Amay be provided with values412representing prescribed and/or targeted rates of pressure change. The pressure changes may be carried out in a step-wise and/or continuous fashion. The prescribed pressure change rates412may be retrieved from a computer readable medium or any storage medium424, and/or may be entered by an operator via an interface provided by the control and data acquisition system106ofFIGS. 1 and 2. The example fluid isolation and analysis tool126may include any type of pressure and temperature (P/T) sensor428configured to measure the pressure and/or the temperature of the fluid in the test flowline408at a plurality of times {t0, t1, t2, . . . , tn}, and to communicate the measured pressures to the controller420. The example processor470may be configured to determine, measure and/or compute actual rates of the pressure change in the test flowline408from the measured pressures. For example, the actual rates of the pressure change may be determined by fitting a curve to a portion of the measured pressures at the plurality of times {t0, t1, t2, . . . , tn}, and determining a slope of the curve. The fitting may be performed using, for example, a least-squares algorithm such as the Savitzky-Golay filter or an iterative re-weighted least-squares algorithm.

The example controller420ofFIG. 4Amay be configured to drive the example motor416via control signals432representing prescribed angular speeds and/or rotations per minute (rpm). The controller420may be configured to execute instructions stored on the computer readable medium424that, when executed, cause the fluid isolation and analysis tool126to induce or affect the targeted rates412of pressure change of the formation fluid in the test flowline408. For example, the angular speed of the motor416may be selected such that the rate of pressure change of the formation fluid in the test flowline408resulting from the motor rotation reduces the differences between the target pressure change ranges and the actual pressure change rates computed by the processor470. The controller420may be configured to implement a feedback control process to determine the control signals432. An example feedback control process is a proportional-integral-derivative (PID) controller, which is commonly used in industrial control applications.

The fluid isolation and analysis tool126ofFIGS. 4A and 4Bmay further include a four-port, two-position valve436. The example four-port two-position valve436ofFIGS. 4A-4Cmay be used to selectively flow a formation fluid admitted into the fluid isolation and analysis tool126via a main flowline440through the test flowline408(as shown inFIG. 4B), and/or to seal, trap and/or capture a portion of the formation fluid in the test flowline408(as shown inFIG. 4C).

The example test flowline408ofFIGS. 4A-4Cmay include any number and/or type(s) of sensor(s), tools(s) and/or fluid analysis module(s), in addition to or instead of the P/T sensor428, to measure other properties of the formation fluid in the test flowline408. Other example sensor(s) that may be implemented include, but are not limited to, the scattering detector (SD)444, which may be configured to measure the amount of light that passes through the formation fluid, and/or a DV sensor448, which may be configured to measure fluid density and/or viscosity. The example sensors428,444and448, a circulating pump (CP)452, the example pressure changing device404, and the example valve436may be arranged along the test flowline408in any order.

The example test flowline408ofFIGS. 4A-4Cmay be provided with the CP452. The example CP452ofFIGS. 4A-4Cmay be used to agitate the formation fluid in the test flowline408by inducing a flow of formation fluid in the test flowline408. For example, a portion of the formation fluid sealed in the test flowline408may be circulated in the test flowline408, as shown inFIG. 4C. The example CP452may help to mix and/or agitate the fluid in the test flowline408so that any phase-changes (e.g., bubble formation) may be sensed by all the example sensors428,444and448of the test flowline408.

To measure any number and/or type(s) of additional fluid properties, the example main flowline440may include any number and/or type(s) of additional sensor(s), tools(s) and/or fluid analysis module(s). Additional sensor(s), tool(s) and/or fluid analysis module(s) that may be implemented include, but are not limited to the Schlumberger InSitu Fluid Analyzer™456, which may include, among other things, a DV sensor460and a multi-channel spectrometer (SP)464. The example IFA456may be used to measure and/or determine, among other things, a gas/oil ratio (GOR), an optical density, and/or a fluid type. While in the illustrated example ofFIG. 4A, the IFA456is implemented upstream from the fluid isolation and analysis tool126it may, alternatively, be implemented downstream from the fluid isolation and analysis tool126.

The fluid isolation and analysis tool126ofFIG. 4Amay comprise a processor470communicatively coupled to any or all of the example sensors428,444,448,456,460and464. In cases where the fluid isolation and analysis tool126is part of any of the example downhole tools100and/or250ofFIGS. 1,2, and3, the example processor470may be implemented within the downhole tool100and/or250. Additionally or alternatively, the processor470may be implemented at the Earth's surface by, for example, the example processor106B of the example control and data acquisition system106. The example processor470ofFIG. 4may be configured to determine, based on the measurements taken by one or more of the example sensors428,444,448,456,460and464during a systematic (de-)pressurization of the fluid in the test flowline408, the phase-change pressure of the fluid in the test flowline408. For example, the processor470may be configured to execute instructions stored on, for example, the storage or tangible computer readable medium424that, when executed, cause the processor470to carry out the example process ofFIGS. 16A and 16B. Phase-change pressures and/or phase-change onset points may be stored in the example storage424for subsequent retrieval and/or processing at the surface, and/or may be transmitted via telemetry to the example control and data acquisition system106.

While the example controller420ofFIG. 4Asystematically pressurizes and/or depressurizes the fluid in the test flowline408according to the pressure rates412, one or more of the example sensors428,444,448may measure one or more properties of the fluid in the test flowline408at corresponding ones of the times {t0, t1, t2, . . . , tn}. For example, the scattering sensor444may measure a plurality of light transmissions {x0, x1, x2, . . . xn} through the fluid in the test flowline408for respective ones of the times {t0, t1, t2, . . . , tn}, which correspond to respective ones of the fluid pressures measured by the P/T sensor428. The other example sensors456,460and464may likewise measure other properties of the fluid. In general, the example fluid isolation and analysis tool126may measure, during a systematic (de-)pressurization process, pressure and temperature versus time using the example P/T sensor428, viscosity and density versus time using the example DV sensor448, scattering detector response versus time using the example SD444, and/or (de-)pressurization rate and volume versus time.

The phase-change pressure of the fluid in the test flowline408may be determined from the measured light transmittances {x0, x1, . . . xn}. During depressurization of the fluid, the amount of light transmitted through the fluid may be substantially constant, provided that the fluid remains in its single phase during depressurization. However, when the pressure of the fluid reaches a phase-change pressure, gas bubbles, liquid droplets and/or asphaltene particles may emerge from the fluid and may begin scattering light. When the light passing through the fluid is scattered, the light transmittance of the fluid may be reduced. Detection of a change in the light transmittance of the fluid may be used by, for example, the processor470to detect the onset of the phase-change.

FIGS. 5A and 5Bshow scattering detector responses505and510, measured by the example sensor444during depressurization of two different live fluids, respectively. Properties of these two example live fluids as well as other example fluids discussed herein are shown inFIG. 5C. As used herein, a scattering detector response represents a ratio of the voltage used to power a lamp to generate a transmitted light signal and a photo-detector output voltage of the SD444representing the amount of light that passed through the fluid. The ratio, rather than the photo-detector output voltage, may be used to reduce or minimize any effect(s) caused by a possibly changing power supply voltage of the lamp during (de-)pressurization. Therefore, the scattering detector response represents light transmittance through the fluid in the test flowline408. While in the example graphs depicted throughout this disclosure, the direction of depressurization is synchronized with the progression of time, the fluid may alternatively be pressurized in synchronization with the progression of time. Before the onset of phase-change is reached, the response may be either flat (as shown inFIG. 5A) or sloped (as shown inFIG. 5B) as the pressure in the flow flowline408decreases. Differences in the responses505and510may be caused by a combined effect of color absorption, fluid compressibility and fluid density. An example scattering detector444uses a transmitted light wavelength of 1600 nanometers (nm), which is a wavelength at which the absorption of transmitted light may be affected by the electronic excitation, color effect of the fluid and/or light scattering. For gas condensate and light oil (such as shown inFIG. 5A), there is little electronic excitation absorption and/or color absorption at this wavelength, whereas for a darker and heavier live oil (as shown inFIG. 5B) the absorption caused by electronic excitation may be discernible. As the density of the fluid decreases with decreasing pressure during depressurization, the absorption of transmitted light decreases and as a result, the light transmittance510may increase for the darker and heavier live oil as shown inFIG. 5B. For gas condensate and light oil, however, there may be little change in light transmittance505by electronic excitation even though the density of fluid decreases during depressurization. Therefore, the scattering detector response505may remain nearly flat for pressures greater than the onset of phase-change, as shown inFIG. 5A.

When the onset of phase-change is reached, the light passing through the fluid may be partially or wholly scattered and, consequently, the scattering detector responses505and510decrease as shown inFIGS. 5A and 5B. In response to the emerging gas bubbles, the reduction in light transmittance may decrease abruptly as shown inFIG. 5Aor may gradually decay as shown inFIG. 5B. The example methods and apparatus disclosed herein may be configured to automatically detect the onset of phase-change in either situation. The example methods and apparatus disclosed herein may use fluid properties measured by one or more of the other sensors428,448,456,460and/or464to confirm, collaborate and/or quality check a phase-change pressure determined based on light transmittance measurements.

Denoting xias the scattering detector response at the ithtime index during (de-)pressurization, the example processor470ofFIG. 4Amay compute an energy ratio ei, which may be expressed mathematically as:

ei=10*log10(∑k=i-wk=i-1⁢xk2∑k=ik=i+w-1⁢xk2)EQN⁢⁢(1)
where the denominator within the parentheses is called the front energy (FE) and the numerator is called the back energy (BE), respectively, at the time index i, and w is a window size. The example energy ratio eiof EQN (1) has units of decibels (dB). The FE represents the energy of the light transmittances xiin a front energy window that includes the current time index i and extends forward w−1 samples. The BE represents the energy of the light transmittances xiin a back energy window that includes the preceding time index i−1 and extends backwards w−1 samples. Note that before the onset of phase-change is reached, the ratio in the parentheses of EQN (1) should be less than or equal to 1 and, therefore, the energy ratio eiis less than or equal to zero. However, when phase-change onset is reached, the energy ratio eiwill increase and will become larger than zero. Accordingly, the processor470may compare the energy ratio eito a threshold to detect the onset of phase-change.

In practice, the energy ratio eiof EQN (1) may be efficiently computed. For example, by defining a cumulative sum of energy

c⁢⁢ei=∑k=1k=i⁢xk2,EQN⁢⁢(2)
the energy ratio eican be expressed as

FIGS. 6A-6CandFIGS. 7A-7Bdepict an example computation of the energy ratio eidescribed above.FIG. 7Adepicts an example scattering detector response705withFIG. 7Bdepicting a corresponding computed energy ratio710. In the example ofFIG. 7B, the size of window w is set equal to 3.FIGS. 6A-6Cdepict the step-by-step calculation of the example energy ratio710ofFIG. 7Baround the onset of phase-change. InFIG. 6A, the FE and BE windows are depicted as respective boxes605and610in the top subplot, and the computed energy ratio eibased on the computed FE and BE is registered in the bottom subplot at the corresponding time index, as shown by an arrow615.FIGS. 6B and 6Cshow the subsequent scattering detector response and the corresponding energy ratios at subsequent time indices.

Returning toFIGS. 7A and 7B, the phase-change onset may be detected by identifying the data point715corresponding to when the energy ratio ei710exceeds a detection threshold. As described above, the increase in the energy ratio ei710is caused by the drop of scattering detector response705in the FE window and, therefore, the proper registration of phase-change onset corresponds to data point720inFIG. 7A, which is shifted to the right by w−1 (i.e., the window size w less one) from the detection of onset at point715ofFIG. 7B.

The detection threshold may be selected as a small fixed value. In the examples described herein a threshold of 0.05 was used. Alternatively, the detected threshold may be selected based on a running statistic computed during (de-)pressurization. For example, a running standard deviation δiof the energy ratio eimay be computed as
δi=√{square root over (vi−mi2)},  EQN (4)
where

vi=1i⁢∑k=1k=i⁢ek2,EQN⁢⁢(5)mi=1i⁢∑k=1k=i⁢ek,EQN⁢⁢(6)
and i is the number of samples used to compute the statistic in EQNS (4)-(6). Note that example expressions of EQNS (5) and (6) may be computed recursively using the following mathematical expressions:

The time-varying detection threshold may be set equal to three times the standard deviation δiat each time index i after, for example, at least 10 samples of the energy ratio eiare available for computing the statistic. Alternatively, as described above, a fixed detection threshold may be used.

Measurements from other sensors of the example flowline408(e.g., the example P/T sensor428and/or the DV sensor448) and/or other properties and/or quantities derived from these measurements may be used by the processor470to validate, confirm and/or quality check phase-change pressures determined based on light transmittances measured by the example SD444.

FIG. 8depicts graphs of example measurements taken while the example live oil1ofFIG. 5Cis undergoing depressurization. The top two subplots are the scattering detector response805and the corresponding computed energy ratio810, respectively. A point815on the computed energy ratio graph810corresponds to the energy ratio eithat exceeds the detection threshold and, therefore, may be used to identify the onset of phase-change at point820, which may be identified by shifting to the right from the identified point815by w−1, wherein w is the size w of the FE and BE windows. In the example ofFIG. 8, gas bubbles emerge when the onset of phase-change, which in the example ofFIG. 8is the bubble point, is reached.

A third subplot inFIG. 8depicts example temperature readings825measured by the P/T sensor428. As shown inFIG. 8, a decreasing trend in temperature825may occur during depressurization. However, at the onset of phase-change when the gas bubbles emerge, the temperature825may reverse its trend, as shown inFIG. 8. Therefore, temperature measurements825taken during depressurization may be used by the example processor470to corroborate and/or validate the detected phase-change820.

A fourth subplot inFIG. 8represents the depressurization rate830in psi/min, as computed and/or derived by the example controller420. In the example ofFIG. 8, the planned and/or intended depressurization rate is 1000 psi/min. However, as shown inFIG. 8, at the onset of phase-change, the actual depressurization rate830may deviate from the planned rate of 1000 psi/min. This is because, when the gas bubbles emerge at the onset of bubble point, the pressure reduction830of the fluid may become slower than before and the controller420may not immediately be able to compensate for this abrupt change in fluid properties. Therefore, a depressurization signature comprising an abrupt and/or unexpected reduction of the depressurization rate830from the planned value may be used by the processor470to confirm the onset of phase-change.

The bottom subplot ofFIG. 8depicts pressures835measured by the example P/T sensor428during the depressurization. The measured pressures835at the time corresponding to the detected phase-change onset corresponds to the phase-change pressure. The phase-change pressure identified inFIG. 8is 4061 psi, which agrees well with Pbof 4060 psi measured using a constant composition expansion (CCE) procedure performed in a laboratory. Note that the pressure versus time profile835ofFIG. 8is nearly linear without distinct features, making the detection of phase-change pressure from this pressure profile835difficult and/or less reliable.

FIG. 9depicts a graph of pressures905versus the extended volume (i.e., PV data) for the example depressurization of live oil1depicted inFIG. 8. The example data905ofFIG. 9shows a smooth transition around the onset910of phase-change, which may make a reliable and/or accurate detection of the phase-change pressure based on the example PV data905difficult. However, for some fluids PV data may be used by the processor470to confirm and/or corroborate the detection of the onset of phase-change.

The fluid densities and/or viscosities measured by the example DV sensor448during depressurization may, additionally or alternatively, be used to validate, confirm and/or quality control the phase-change pressures determined from light transmittances.FIG. 10shows example SD responses1005, example densities1010and example viscosities1015measured for a volatile oil during depressurization without circulation. A point1020in the top subplot ofFIG. 10corresponds to the onset of phase-change (e.g., bubble point) detecting using the energy ratio eidescribed above. While the measured fluid is still in single phase, the fluid densities1010and the fluid viscosities1015exhibit a generally linearly decreasing trend with decreasing pressure. Once the onset1020of phase-change is reached, gas bubbles emerge and the fluid densities1010and the fluid viscosities1015in the two-phase fluid may abruptly deviate from the single-phase trend as shown inFIG. 10. These deviations of the densities1010and/or the viscosities1015from the single-phase trend may, therefore, be used by the example processor470to confirm the detected phase-change1020.

FIGS. 11-16illustrate example sensor measurements and energy ratios, as described above in connection withFIG. 8, for other example fluids. As shown in the examples ofFIGS. 11-16, the example methods and apparatus to determine phase-change pressures disclosed herein are applicable to any number and/or type(s) of fluids.

InFIG. 11, the example live oil2ofFIG. 5Chas been depressurized. Unlike the example ofFIG. 8, the scattering detector response1105decreases gradually at and after the onset of phase-change. However, the example methods and apparatus described herein correctly identify the onset of phase-change and the corresponding phase-change pressure1110(saturation pressure). As discussed above, a point1115on the computed energy ratio curve1120corresponds to when the energy ratio1120exceeds the detection threshold. Furthermore, the temperature measurements1125and the depressurization rates1130corroborate the detected onset of phase-change.

FIG. 12shows the results for the example live oil3ofFIG. 5C. In the illustrated example ofFIG. 12, the fluid undergoes a faster depressurization at a rate of 1500 psi/min. The detected onset of phase-change using the methods and apparatus described herein is consistent with the reverse trend in temperature measurement and the signature drop in the depressurization rate at the phase-change onset. The detected saturation pressure inFIG. 12is 2501 psi, which is in agreement with the CCE Pbof 2543 psi measured in a laboratory.

FIG. 13shows example results for the example live oil4ofFIG. 5C. Live oil4is very dark in color and is the most viscous among all example fluids shown inFIG. 5C. From the scattering detector response1305shown in the top subplot ofFIG. 13, the light transmission through live oil4is weaker in comparison with the examples discussed above, but the light transmittance is still measurable. Before reaching the onset of phase-change, the scattering detector response1305increases slightly as the pressure decreases, which is caused by the combined effect of color absorption and fluid density as explained above. The computed energy ratio1310is predominately less than zero before the onset is reached. At the scale that the computed energy ratio1310is shown inFIG. 13, the fluctuations in the computed energy ratio1310represent noise in the scattering detector data1305. The onset of phase-change is detected at 1603 psi in agreement with CCE Pbof 1550 psi. The detected onset is further corroborated and confirmed by the reverse temperature trend and the signature drop in the depressurization rate that occurred at the onset of phase-change. In the example ofFIG. 13, the pressure versus time profile shown in the bottom subplot changes at the phase-change pressure, which may also be used to corroborate and/or confirm the detected onset of phase-change.

FIG. 14shows example results for the example gas condensate ofFIG. 5C. In this example, liquid droplets emerge when the onset of phase-change is reached. As shown, the onset of phase-change may be detected using the example methods and apparatus disclosed herein. The detected saturation pressure (i.e., dew point pressure in this case) is 6808 psi, which again is in a good agreement with the CCE Pdof 6760 psi measured in a laboratory. However, the reverse trend in temperature reading and the signature drop in the depressurization rate at the phase-change onset are not apparent for gas condensate, as shown inFIG. 14. The lack of correlation of temperature reading and/or depressurization rate with the onset of phase-change may be used to perform, for example, fluid identification (i.e. gas condensate vs. live oil) when combined with other measurements.

FIG. 15shows example results for the example asphaltene live oil ofFIG. 5C. For asphaltene oil, there are typically two onsets corresponding to different fluid phase-changes. The first occurs at a higher onset pressure where the asphaltene particulates precipitate whereas the second happens at a lower onset pressure where the gas bubbles emerge from fluid. The former is called the AOP and the latter is the bubble point pressure. It may be useful to be able to identify the presence of asphaltene and its onset in situ. Depending on the composition of formation fluid the presence of AOP may or may not occur during depressurization. One method that may be used to identify the presence of AOP is to measure the colloidal instability index of reservoir fluid. However, methods to measure the colloidal instability index may not be applicable for downhole applications. As shown inFIG. 15, the methods and apparatus described herein may be used downhole to detect the asphaltene onset in situ. To identify whether an observed reduction in light transmittance is caused by asphaltene precipitation or emerging gas bubbles, the other example measurements depicted inFIG. 15may be used to delineate the occurrence of AOP. As shown inFIG. 15, asphaltene precipitation causes a reduction of light transmission but does not coincide with a reversal of the temperature trend or the signature drop in the depressurization rate. Additionally or alternatively, a GOR of the fluid determined using the example SP464may be used to distinguish asphaltene live oil from gas condensate and thereby identify the presence of AOP, even though the dew point of gas condensate may show similar sensor responses, as discussed above in connection withFIG. 14. When the gas bubbles finally emerge at a lower onset pressure (around 1150 seconds inFIG. 15), an additional drop in the scattering detector response accompanied by the reverse trend in temperature reading and the signature drop in the depressurization rate may be used by the example processor470to detect the onset of bubble point. As shown inFIG. 15, the example methods and apparatus described herein may be used to identify and/or detect both AOP and bubble point pressure, without having to measure the colloidal instability index of fluid in a laboratory.

While an example fluid isolation and analysis tool126that may be used to determine phase-change pressures and/or detect phase-change onset is shown inFIGS. 4A-C, one or more of the elements, sensors, circuits, modules, processors, controllers and/or devices illustrated inFIGS. 4A-Cmay be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way. Further, any of the example elements, sensors, circuits, modules, processors, controllers, devices and/or more generally the example fluid isolation and analysis tool126ofFIGS. 1-3and4A-4C may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware. Thus, for example, any or all of the example elements, sensors, circuits, modules, processors, controllers, devices and/or more generally the example fluid isolation and analysis tool126may be implemented by one or more circuit(s), programmable processor(s), application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), field-programmable logic device(s) (FPLD(s)), field-programmable gate array(s) (FPGA(s)), etc. Further still, the fluid isolation and analysis tool126may include elements, sensors, circuits, modules, processors, controllers and/or devices instead of or in addition to those illustrated inFIGS. 4A-C, and/or may include more than one of any or all of the illustrated elements, sensors, circuits, modules, processors, controllers and/or devices.

FIGS. 16A and 16Aare a flowchart representative of an example process that may be carried out to implement the example fluid isolation and analysis tool126ofFIGS. 1-3and4A-4C. The example process ofFIGS. 16A and 16Amay be carried out by a processor, a controller and/or any other suitable processing device. For example, the example process ofFIGS. 16A and 16Amay be embodied in coded instructions stored on an article of manufacture such as any tangible computer-readable and/or computer-accessible media. Example tangible computer-readable medium include, but are not limited to, a flash memory, a compact disc (CD), a digital versatile disc (DVD), a floppy disk, a read-only memory (ROM), a random-access memory (RAM), a programmable ROM (PROM), an electronically-programmable ROM (EPROM), and/or an electronically-erasable PROM (EEPROM), an optical storage disk, an optical storage device, magnetic storage disk, a magnetic storage device, and/or any other tangible medium which can be used to store and/or carry program code and/or instructions in the form of machine-accessible and/or machine-readable instructions or data structures, and which can be accessed by a processor, a general-purpose or special-purpose computer, or other machine with a processor (e.g., the example processor470ofFIG. 4Aand/or the example processor platform P100discussed below in connection withFIG. 17). Combinations of the above are also included within the scope of computer-readable media. Machine-readable instructions comprise, for example, instructions and/or data that cause a processor, a general-purpose computer, special-purpose computer, or a special-purpose processing machine to implement one or more particular processes. Alternatively, some or all of the example process ofFIGS. 16A and 16Amay be implemented using any combination(s) of ASIC(s), PLD(s), FPLD(s), FPGA(s), discrete logic, hardware, firmware, etc. Also, some or all of the example process ofFIGS. 16A and 16Amay instead be implemented manually or as any combination of any of the foregoing techniques, for example, any combination of firmware, software, discrete logic and/or hardware. Further, many other methods of implementing the example operations ofFIGS. 16A and 16Amay be employed. For example, the order of execution of the blocks may be changed, and/or one or more of the blocks described may be changed, eliminated, sub-divided, or combined. Additionally, any or all of the example process ofFIGS. 16A and 16Amay be carried out sequentially and/or carried out in parallel by, for example, separate processing threads, processors, devices, discrete logic, circuits, etc.

The example process ofFIGS. 16A and 16Bbegins with the example processor470comparing one or more of a GOR value measured by the example SP464, an optical density (OD) value and/or a fluid density value to respective thresholds to identify and/or determine a fluid type (block1605). For example, a GOR threshold of 3300 standard cubic feet per stock tank barrel (scf/stb) may be used to separate crude oil from gas condensate. The separation of fluid type may be used to determine whether circulation of the fluid by the CP452is required during depressurization. Additionally or alternatively, the OD in the visible and/or near-infrared region may be measured by the SP464and used to identify the fluid type. For example, crude oil typically exhibits some coloration while gas condensate is nearly colorless. This is particularly true for crude oil containing asphaltenes which may contribute significant color absorption. Accordingly, one may set a low OD threshold of, for example, 0.1 for the identification of fluid type. Further still, one can also include the density of fluid measured by the DV sensor460,448to identify the fluid type. The density threshold, for example, can be set at 0.4 grams per cubic centimeter (g/cm3) to roughly separate crude oil from gas condensate.

If a crude oil is identified at block1605, circulation of the fluid in the flowline408by the CP452is started (block1610), and the controller420begins systematically depressurization of the fluid (block1615). As the fluid is depressurized, the example processor470computes the example energy ratio eifrom the light transmittances measured by the example SD444(block1620).

If the energy ratio eidoes not exceed the detection threshold (block1625), control returns to block1620to continue computing energy ratio values. When the energy ratio eiexceeds the detection threshold (block1625), the processor470determines whether the temperatures measured by the P/T sensor428exhibit a temperature reversal and the pressurization rates computed by the controller420exhibit a signature drop (block1630).

If the temperature reversal and/or the pressurization rate drop are found (block1630), the onset of bubble pressure has been detected (block1635). The onset of bubble pressure may be validated, collaborated and/or quality checked using other measurements such as density and/or viscosity (block1640), as described above in connection withFIG. 10. While the example DV sensor448is more accurate when the fluid in the test flowline408is not moving or flowing during measurement of the densities and/or viscosities, other DV sensors that work accurately and/or reliably in the presence of a vibrating fluid pump may be implemented. Depressurization of the fluid is discontinued and the fluid is re-pressurized to a pressure substantially equal to the pressure of the main flowline440(block1645). Control then exits from the example process ofFIGS. 16A and 16B.

Returning to block1630, if the temperature reversal and/or the pressurization rate drop did not occur (block1630), and this is not the first time that the energy ratio eiexceeded the threshold (block1650), control returns to block1620. If this is the first time that the energy ratio eiexceeded the threshold (block1650), then the onset of AOP has been detected (block1655). Control then returns to block1620to detect the onset of bubble point.

Returning to block1605, if a crude oil has not been identified (block1605), control proceeds to block1660ofFIG. 16B. At block1660ofFIG. 16B, the controller420begins systematically depressurizing the fluid without circulation. As the fluid is depressurized, the example processor470computes the example energy ratio eifrom the light transmittances measured by the example SD444(block1665).

If the energy ratio eidoes not exceed the detection threshold (block1670), control returns to block1665to continue computing energy ratio values. When the energy ratio eiexceeds the detection threshold (block1670), the processor470determines whether the temperatures measured by the P/T sensor428exhibit at temperature reversal and the pressurization rates computed by the controller420exhibit a signature drop (block1675).

If the temperature reversal and/or the pressurization rate drop are found (block1675), the bubble point pressure has been detected (block1680). Control then proceeds to block1640ofFIG. 16A.

If the temperature reversal and/or the pressurization rate drop are not found (block1675), the dew point pressure has been detected (block1685). Control then proceeds to block1640ofFIG. 16A.

FIG. 17is a schematic diagram of an example processor platform P100that may be used and/or programmed to implement the example fluid isolation and analysis tool126ofFIGS. 1-3,4A-C and/or the example process ofFIGS. 16A and 16B. For example, the processor platform P100can be implemented by one or more general-purpose processors, processor cores, microcontrollers, etc.

The processor platform P100of the example ofFIG. 17includes at least one general-purpose programmable processor P105. The processor P105executes coded instructions P110and/or P112present in main memory of the processor P105(e.g., within a RAM P115and/or a ROM P120). The processor P105may be any type of processing unit, such as a processor core, a processor and/or a microcontroller. The processor P105may carry out, among other things, the example process ofFIGS. 16A and 16Bto determine phase-change pressures and/or detect phase-change onsets.

The processor P105is in communication with the main memory (including a ROM P120and/or the RAM P115) via a bus P125. The RAM P115may be implemented by dynamic random-access memory (DRAM), synchronous dynamic random-access memory (SDRAM), and/or any other type of RAM device, and ROM may be implemented by flash memory and/or any other desired type of memory device. Access to the memory P115and the memory P120may be controlled by a memory controller (not shown). The memory P115, P120may be used to implement the example storage424ofFIG. 4A.

The processor platform P100also includes an interface circuit P130. The interface circuit P130may be implemented by any type of interface standard, such as an external memory interface, serial port, general-purpose input/output, etc. One or more input devices P135and one or more output devices P140are connected to the interface circuit P130. The example output device P140may be used to, for example, control the example motor416. The example input device P135may be used to, for example, receive measurements from the example sensors428,444,448,456,460and/or464.

In view of the foregoing description and the figures, it should be clear that the present disclosure introduces methods and apparatus to determine phase-change pressures. In particular, the present disclosure introduces methods including capturing a fluid in a chamber, (de-)pressurizing the fluid at a plurality of pressures, measuring a plurality of transmittances of a signal through the fluid at respective ones of the plurality of pressures, computing a first magnitude of a first subset of the plurality of transmittances, computing a second magnitude of a second subset of the plurality of transmittances, comparing the first and second magnitudes to determine a phase-change pressure for the fluid.

The present disclosure further introduces formation fluid analysis tools including a flowline, a valve configured to capture a fluid in the flowline, a pressure control unit configured to (de-)pressurize the fluid at a plurality of pressures, a scattering detector configured to measure a plurality of transmittances of a signal through the fluid at respective ones of the plurality of pressures, and a processor configured to compute a first magnitude of a first subset of the plurality of transmittances, compute a second magnitude of a second subset of the plurality of transmittances, comparing the first and second magnitudes to determine a phase-change pressure for the fluid.