US20170082765A1 - Thermal Modulated Vibrating Sensing Module for Gas Molecular Weight Detection - Google Patents

Thermal Modulated Vibrating Sensing Module for Gas Molecular Weight Detection Download PDF

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US20170082765A1
US20170082765A1 US15/311,246 US201415311246A US2017082765A1 US 20170082765 A1 US20170082765 A1 US 20170082765A1 US 201415311246 A US201415311246 A US 201415311246A US 2017082765 A1 US2017082765 A1 US 2017082765A1
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wellbore
formation fluid
gas
sensor
sensing module
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Hua Xia
Christopher Michael Jones
Robert Atkinson
Tian He
Bin Dai
Jing Shen
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Assigned to HALLIBURTON ENERGY SERVICES, INC. reassignment HALLIBURTON ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: HE, Tian, ATKINSON, ROBERT, DAI, Bin, SHEN, JING, JONES, CHRISTOPHER MICHAEL, XIA, HUA
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/46—Data acquisition
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/081—Obtaining fluid samples or testing fluids, in boreholes or wells with down-hole means for trapping a fluid sample
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
    • E21B49/087—Well testing, e.g. testing for reservoir productivity or formation parameters
    • E21B49/0875—Well testing, e.g. testing for reservoir productivity or formation parameters determining specific fluid parameters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/002—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity using variation of the resonant frequency of an element vibrating in contact with the material submitted to analysis
    • E21B2049/085—
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E21B47/07—Temperature
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/002—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity using variation of the resonant frequency of an element vibrating in contact with the material submitted to analysis
    • G01N2009/004—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity using variation of the resonant frequency of an element vibrating in contact with the material submitted to analysis comparing frequencies of two elements
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N9/00—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity
    • G01N9/002—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity using variation of the resonant frequency of an element vibrating in contact with the material submitted to analysis
    • G01N2009/006—Investigating density or specific gravity of materials; Analysing materials by determining density or specific gravity using variation of the resonant frequency of an element vibrating in contact with the material submitted to analysis vibrating tube, tuning fork

Definitions

  • the present disclosure generally relates to the identification of wellbore formation fluids and, more particularly, to averaged gas molecular weight detection with a thermal modulated vibrating sensing module, and related methods utilized for in-situ identification of wellbore formation gas fluids.
  • Averaged gas molecular weight is closely related to the hydrocarbon composition of wellbore formation fluid from a hydrocarbon gas reservoir and to the pressure-temperature diagram of a multi-component system with a specific overall composition.
  • pressure and temperature can alter gas density, and the measured formation fluid density can vary significantly from dry, wet or saturated gases.
  • average gas molecular weight of a hydrocarbon gas mixture will be the same if the reservoir composition is kept constant, regardless of the temperature and pressure variations.
  • the averaged gas molecular weight variation may provide a direct correlation to formation gas fluid composition and properties, which is normally obtained only by offline gas chromatography analysis.
  • Gas molecular weight detection is a particularly important concept in the field of flow measurement, as the varying densities of the constituent material may present a significant problem in natural gas production.
  • the natural gas is a mixture of hydrocarbon compounds, dominated by C1-C4, with quantities of various non-hydrocarbons such as N 2 and H 2 .
  • extra small quantities of C5+ may also exist in the liquid phase.
  • the amount of hydrocarbons present in the liquid phase of the wet gas extracted depends on the reservoir temperature and pressure conditions, which change over time as the gas and liquid are removed.
  • a conventional laboratory method is to use either gas chromatography (GC) or gas chromatography (GC) and mass spectroscopy (MS) combined GC-MS instrument.
  • GC gas chromatography
  • MS mass spectroscopy
  • FIG. 1A is block diagrammatical illustration of a thermal modulated vibrating tubing based gas molecular weight sensing module according to certain illustrative embodiments of the present disclosure
  • FIG. 1B is an exploded view of a single gas sensor package, according to certain illustrative embodiments of the present disclosure
  • FIGS. 2A and 2B are alternative illustrative embodiments of gas sensing module in which two gas sensors are arranged in series configuration ( FIG. 2A ) and parallel configuration ( FIG. 2B );
  • FIGS. 3A and 3B are plots showing hydrocarbon boiling points and molecular weight as a function of the carbon number, respectively;
  • FIG. 4 is a pressure-temperature phase diagram that is used for fluid phase control, according to an illustrative method of the present disclosure
  • FIG. 5 is a diagram illustrating the pressure-temperature phase envelop under three different gas molecular weights, according to an illustrative method of the present disclosure.
  • FIG. 6 illustrates an embodiment of the present disclosure whereby a gas molecular weight sensing module is utilized in a wireline application.
  • the sensing module includes a pair of gas sensors, each comprising a vibrating tube having a mechanism thereon for vibrational excitation and signal acquisition.
  • Each gas sensor includes a thermal modulated hollow tube body having a venturi inlet and outlet to regulate fluid flow uniformity.
  • the vibrating tube is coupled between the venturi inlet and outlet.
  • Pressure and temperature sensors are positioned along the sensing module to provide temperature and pressure compensated vibrational measurements from the resonant frequency of the vibrating tube.
  • the sensing module may be utilized as a standalone device for gas production monitoring, or as part of a downhole assembly such as, for example, a sampling tool deployed along a wireline or drilling assembly for identifying formation fluid composition (such as gas, oil, water or their mixtures).
  • formation fluid composition such as gas, oil, water or their mixtures.
  • the averaged gas molecular weight could be an indicator of the reservoir composition.
  • wellbore formation fluid flows into the sensing module and to the first and second gas sensors (also referred to herein as gas sensor packages), which are operated under temperatures T 1 and T 2 , respectively.
  • the first and second gas sensors also referred to herein as gas sensor packages
  • T 1 and T 2 temperatures
  • the resonant frequencies of the hollow tubes are simultaneously measured at two different temperature operating modes, and each gas sensor package is kept in an isothermal status.
  • These vibrational measurements include the resonant frequencies of the vibrating tubes as the formation fluid flows through (for gas density determination), in addition to the temperature and pressure measurements of each gas sensor.
  • the differential pressure measurements across the sensing module are then utilized to determine the gas molecular weight of the formation fluid.
  • Embodiments of the present disclosure are useful to analyze a number of different formation fluid compositions.
  • the sensing module may be used for in-situ dry gas well analysis.
  • the sensing module can be used for wet gas analysis, where the small quantity of formation liquid may coexist with the gas.
  • the gas sensing module may be used for saturated gas analysis, where gas can separate from the crude oil in the formation fluid when pressure is above the bubble point. Accordingly, the use of various embodiments of the present disclosure provided are to enhance sampling tool abilities for in-situ averaged gas molecular weight measurements of dry, wet, and saturated hydrocarbon gas reservoirs.
  • wellbore fluid is a mixture of various hydrocarbons, and their averaged molecular weight can be obtained by first measuring each individual gas composition, then, then determining each gas composition's mole percentage or weight percentage. Traditionally, this is done in a laboratory condition using a gas chromatography technique.
  • embodiments of the present disclosure provide a sensing module discussed that directly measures averaged gas molecular weight without the need to identify each gas composition and its percentage in total volume.
  • average gas molecular weight is closely related to the hydrocarbon composition of wellbore formation fluid from a hydrocarbon gas reservoir, in addition to being closely related to the pressure-volume-temperature (“PVT”) diagram or equation of the state (“EOS”) of a multi-component gas mixture reservoir with a specific overall composition and averaged molecular weight. Therefore, the in-situ measurement of gas molecular weight in the downhole environment described herein will identify the naturally occurring hydrocarbon gas reservoirs and predict phase behavior of the formation fluid.
  • PVT pressure-volume-temperature
  • EOS equation of the state
  • a CH 4 or C 1 dominated natural gas production well may have an averaged molecular weight of equal and greater than 16 g/mol, but any additional C 2 -C 5 , N 2 , and CO 2 could increase the measured molecular weight in a small amount, but averaged gas molecular weight could be an indicator of the gas reservoir composition stability.
  • the measured hydrocarbon gas molecular weight provides a direct correlation to the gas composition of the formation fluid, which in conventional approaches is normally obtained by time-consuming offline gas chromatography analysis.
  • analysis of fluid composition may be conducted in real-time to thereby provide immediate analysis of the hydrocarbon gas composition.
  • downhole sampling tools such as the Halliburton RDTTM, will have added service capability for use in both crude oil and hydrocarbon gas reservoirs.
  • FIG. 1A is a high-level block diagrammatical illustration of a thermal modulated vibrating tube based gas molecular weight sensing module 100 according to certain illustrative embodiments of the present disclosure.
  • Sensing module 100 includes first gas sensor 102 and second gas sensor 104 , which are connected to one another in series fashion. First and second sensors 102 and 104 are operated under isothermal temperatures T 1 and T 2 , respectively, as will be described in more detail below.
  • sensing module 100 is attached to various flow control mechanisms via a front flow line 106 a and back flow line 106 b. As shown, a pressure gauge 108 a, gas flow inlet control valve 110 a, pressure and flow regulator 112 a and a coalesce filter 114 are coupled in series fashion along front flow line 106 a.
  • coalesce filter 114 performs gas purification by blocking debris and solid particles, and minimizing erosions to chokes, flow lines, control valves, and other sensor packages. In some cases, the coalesced water droplets are repelled by hydrophobic barrier layers. In another case, a separator filter with a two-stage vertical coalescer and separator housing will be used to separate gas from hydrocarbon liquid. For practical application, a microporous film produced from ultra-high molecular weight polyethylene (“UHMW”) or low-density porous PTFE filters could be used in high-temperature (up to 500° F.) for venting of the gases while holding oil, liquid and water separation.
  • UHMW ultra-high molecular weight polyethylene
  • PTFE filters could be used in high-temperature (up to 500° F.) for venting of the gases while holding oil, liquid and water separation.
  • a controlled operation temperature and pressure could render the formation fluid in the pure gas phase from its phase diagram.
  • Connected in series along back flow line 106 b is another pressure gauge 108 b, gas flow outlet 110 b, and a back pressure and flow regulator 112 b, all used to maintain differential pressure and constant flow stability through sensing module 100 .
  • Front and back flow lines 106 a,b are in fluid communication with a source of wellbore formation fluid.
  • lines 106 a,b may couple to gas supply pipeline.
  • flow lines 106 a,b would be connected to a downhole tool flow control unit in which to receive wellbore formation fluids under a constant differential pressure.
  • FIG. 1B is an expanded view of a single gas sensor 102 , 104 , according to certain illustrative embodiments of the present disclosure.
  • Gas sensor 102 , 104 includes a hollow tube body 116 having a first end 116 a and second end 116 b.
  • a venturi inlet 118 a is positioned at first end 116 a, and a venturi outlet 118 b is positioned at second end 116 b.
  • a vibrating tube 120 is fluidly coupled between venturi inlet 118 a and outlet 118 b.
  • Vibrating tube 120 is a tube through which wellbore formation fluid flows during operation of sensing module 100 .
  • Vibrating tube 120 may be made of high-strength titanium (Ti) metal, Ti-alloy, carbon fiber reinforced polymer composites (such as PPS and PEEK), with a typical length of 4-10′′ and diameter of 0.1-0.4′′. In most of cases, these tubing materials will work under 400° F. and 25 kpsi downhole conditions.
  • Ti titanium
  • Ti-alloy titanium-alloy
  • carbon fiber reinforced polymer composites such as PPS and PEEK
  • Venturi inlet/outlet 118 a,b allows control of fluid uniformity and pressure through the gas sensors 102 , 104 .
  • the limited gas flowing rate may affect the density and gas molecular weight measurement accuracy if the sensing tube only is not fully filled.
  • the large ratio of the external/internal tube diameters will enable the gas flow rate increase and thereby increase measurement accuracy.
  • vibrational mechanism 122 is positioned on vibrating tube 120 to excite tube 120 into vibration.
  • vibrational mechanism 122 may be a magnet or coil assembly coupled to processing circuitry (not shown) via line A whereby excitation signals are communicated.
  • Vibrational mechanism 122 may also be utilized for signal pickup/acquisition via line B, whereby vibrational measurements (e.g., resonant frequency, gas density, temperature, pressure measurements) are communicated to the processing circuitry.
  • inlet flow line 106 a has a size of ⁇ ft
  • the gas flow from line 106 a to vibrating tube 120 has a size of ⁇ vt , where ⁇ ft > ⁇ vt .
  • gas sensor 102 , 104 also includes a temperature control loop feedback mechanism 124 coupled to a temperature sensor 126 positioned inside the cavity of hollow body 116 .
  • Feedback mechanism 124 may be, for example, a proportional-integral-derivative (“PID”) controller, based on either PRT100 or RTD, which is utilized to maintain gas sensor 102 , 104 , and thus sensing module 100 , in an isothermal condition.
  • PID proportional-integral-derivative
  • a heating element (not shown) is embedded into a layer of the body of hollow tube 116 to thereby maintain the desired temperature of gas sensor 102 , 104 .
  • Another temperature sensor 128 is embedded into the heating element and connected to a thermometer 130 , which is controlled and coupled to control loop feedback mechanism 124 .
  • feedback mechanism 124 is also coupled to processing circuitry. Via the use of sensors 126 and 128 , the temperature of gas sensor 102 , 104 may be monitored and controlled.
  • vibrational excitation mechanism 122 is attached to the surface of vibrating tube 120 for excitation and signal pick up.
  • the front and rear fluid pressures and temperatures (P Inlet , T Inlet , P Outlet , T Outlet ) of the formation fluid can be measured before and after gas flow through gas sensor 102 , 104 via temperature/pressure sensors (not shown).
  • the density variation of the wellbore formation fluid will be measured through use of the venturi vibrating tube resonant frequency shift between the first and second sensors ( FIG. 1A ), accompanied by the simultaneous measurement of the inlet and outlet temperature (T Inlet , T Outlet ) and pressure (P Inlet , P Outlet ).
  • gas sensing module 100 consist of a pair of isothermal feedback controlled vibrating tube-based sensors 102 , 104 , with first sensor 102 operated at temperature T i , and second sensor 104 operated at T 2 .
  • FIGS. 2A and 2B are alternative illustrative embodiments of gas sensing module 100 in which sensors 102 , 104 are deployed in series configuration ( FIG. 2A ) and parallel configuration ( FIG. 2B ).
  • first and second gas sensors 102 a,b are connected to one another in series fashion whereby venturi outlet 118 b of first sensor 102 is connected to venturi inlet 118 a of second sensor 104 .
  • first and second sensors 102 , 104 will show first and second resonant frequencies:
  • a and b are calibration constants at pre-set T 1 and T 2 with a known gas density or molecular weight.
  • the gas molecular weight (MW) is approximately described by:
  • the density difference will be proportional to relative gas molecular weight (MW) change, namely,
  • each gas sensor may provide measured gas molecular weight, and the differential signal of the two gas molecular weights may be directly used for production quality monitoring as indicated by Eq. (4), where gas composition variation could vary measured gas density difference.
  • gas sensing module 100 P includes first and second gas sensors 102 , 104 arranged in a parallel configuration relative to one another.
  • inlet flow line 106 a is a flow splitter that divides the wellbore formation fluid in a percentage of 0-100%, for example, between first gas sensor 102 and second gas sensor 104 , whereby the fluid is then communicated onto venturi inlets 118 a of first and second gas sensors 102 , 104 . After the formation fluid has traversed first and second gas sensors 102 , 104 , it is then recombined at outlet flow line 106 b (which is coupled to venturi outlets 118 b of sensors 102 , 104 ).
  • the flow splitting ratio is 0 or 100%, where the gas flows through only one of the gas sensors at one time if the flow is controlled by an automatic switch valve.
  • the gas sensing module 100 P may require a filter for gas and liquid separation in the front of flowline 106 a.
  • a filter could be a coalesce or centrifugal-based filter that can separate heavy liquid from wet gas stream and thereby allow the gas phase to flow past sensor 102 , 104 .
  • a microporous film produced from UHMW polyethylene or lo-density porous PTFE filters could be used in high-temperatures (up to 500° F., for example) for venting of the gases while maintaining oil, liquid and water separation.
  • the separated hydrocarbon liquid will be forced to pass through the other gas sensor (second sensor 104 in FIG. 2B ), while the gas phase will pass through the sensor (first gas sensor 102 ).
  • gas molecular analysis starts by measuring the wellbore formation fluid (e.g., multi-component hydrocarbon gas mass) using first and second gas sensors 102 , 104 to thereby determine a first and second gas density using:
  • ⁇ 1,2 ( T, f ) ⁇ (0)+ ⁇ * Y ( T )/( f ( T )* L ) 2 Eq (5),
  • the natural vibrational frequency range of tube 120 is from a few hundred Hz to 20 kHz.
  • the gas molecular weight can be expressed as in terms of gas density as:
  • ⁇ 1 ⁇ (0)+( MW )* z ⁇ P 1 /RT 1 Eq (6)
  • ⁇ 1 is the first gas density
  • ⁇ 2 is the second gas density
  • R is the universal gas constant
  • P 1 and P 2 are the pressures inside vibrating tubes 120
  • ⁇ (0) is the sensor calibration constant at T(0).
  • two vibrating tube operation temperatures T 1 and T 2 are preset, along with the feedback control mechanism 124 to thereby maintain isothermal status operation.
  • the pressure (P 1 , P 2 ) inside vibrating tubes 120 can be calculated by:
  • ⁇ is the fluid density
  • ⁇ 1 and ⁇ 2 are flow velocities before gas flowing into the gas sensors 102 , 104 and inside vibrating tube 120 , respectively.
  • T 1 and T 2 should be relative higher than the downhole formation fluid temperature.
  • the measured gas molecular weight is more or less insensitive to sensing module thermal drifting effects by:
  • the gas flow rate along the flowline 106 is another factor which could lead to gas stream temperature variation.
  • feedback mechanism 124 maintains the sensing module in isothermal condition, which greatly mitigates the effects of thermal drift under downhole conditions.
  • Such an isothermal package is critical especially the downhole logging tool is working along wellbore at different depths or temperature zones.
  • the pre-set temperature T 1 can be the maximum of the downhole formation fluid temperature, but T 2 may be preset as high as allowed (based upon tool design), such as, for example, from 350° F. (177° C.) to 800° F. (427° C.).
  • T 2 may be preset as high as allowed (based upon tool design), such as, for example, from 350° F. (177° C.) to 800° F. (427° C.).
  • FIGS. 3A and 3B are plots showing hydrocarbon boiling points and molecular weight as a function of the carbon number, respectively.
  • 3A and 3B may be used as a reference to set the T 2 value.
  • the boiling point is about 300° C.; however, the boiling point will be about 440° C. for carbon number up to 30.
  • the corresponding gas molecular weight can change more than 100 g/mol. In this method, the following may be utilized to calculate molecular weight:
  • the vibrating tube operational temperature (T 1 , T 2 ), inlet pressure P inlet , (shown in FIGS. 1B, 2A and 2B ), and differential pressure ⁇ P may be pre-set to the proper operating point based upon the pressure-temperature (“PT”) phase diagram, as shown in FIG. 4 .
  • PT pressure-temperature
  • the configuration of gas sensors 102 , 104 may be utilized to reduce the gas pressure inside vibrating tube 120 by using a ⁇ P that shifts the operation point outside the two-phase region of FIG. 4 to thereby achieve single gas phase operation.
  • the flowline inlet pressure P may be set higher than the operation point of FIG. 4 to thereby force gas phase operation that can turn two-phase formation fluid into single-phase gas flow.
  • temperature feedback mechanism 124 is provided and fluid line differential pressure may be also adjusted as necessary.
  • a′ (0.4278*R 2 *T c 2.5 /P c ) and b′ (0.0867*R*T c /P c ) are van der Waals constants, defined by the Redlich-Kwong equation at critical temperature, T c , and critical pressure P c ; V can be taken as gas mole volume.
  • the measured gas molecular weight could be used to determine whether the formation fluid composition is dry, wet or saturated gas.
  • Eq. (13) can be used for interpreting the field measured data from Eq. (12) with EOS based PVT modeling and simulation.
  • FIG. 5 illustrates the PT phase envelop under three different gas molecular weights. In reality, 0.87% C7+ may have different molecular weights, such as from 90 to a few hundreds g/cm 3 , for example.
  • a gas reservoir may consist primarily of C1-C4 hydrocarbon gas, but the 0.82% C7+ may have an averaged molecular weight of 97 g/cm 3 . In another case, the 0.82% C7+ may have an averaged molecular weight of 110 g/cm 3 , while in another case, the 0.82% C7+ may have an averaged molecular weight of 130 g/cm 3 . Although the average gas molecular weight only changes from 18.293, 18.402, to 18.566 g/cm 3 in this example, the PT phase envelop diagram, as shown in FIG. 5 , has changed dramatically.
  • the high carbon bonded hydrocarbons of C7-C30 may have limited content as wet gas, which is saturated with ⁇ 1% volume of liquid hydrocarbons, but the gas molecular weight increase could indicate the corresponding PT phase envelop change, which may have a high impact on the well completion design or asset management.
  • the measurement of the average gas molecular weight also can help to understand the transport properties of hydrocarbons through different layers of the subsurface formation. In one example, the increase of the water will decrease measured average gas molecular weight. In another example, because of localized geothermal anomalies, the heavy oil evaporated gas could increase averaged gas molecular weight.
  • carbon dioxide may become rich due to specific geological regions that also increase the measured averaged gas molecular weight.
  • hydrocarbon gas composition changes will modify a well's PT phase envelop diagram. Accordingly, the simulation described here shows that the critical point and gas/liquid due-point curve can be changed by an increase a small amount of the gas molecular weight.
  • the gas molecular weight measurements provide a new method by which to evaluate downhole formation fluid properties.
  • the gas sensor modules may be deployed with an existing RDT sampling tool after integration, or as part of a downhole assembly such as, for example, an independent service of logging-while-drilling (“LWD”) or measurement-while-drilling (“MWD”).
  • LWD logging-while-drilling
  • MWD measurement-while-drilling
  • the methods described above may be performed by processing circuitry onboard a gas sensing module or located at some remote location.
  • processing circuitry would comprises a signal processor, communications module and other circuitry necessary to achieve the objectives of the present disclosure, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure.
  • the software instructions necessary to carry out the objectives of the present disclosure may be stored within storage located within the processing circuitry or loaded into that storage from a CD-ROM or other appropriate storage media via wired or wireless methods.
  • Such software and processing circuitry will enable the processing of high-volume data and interpretation/correlation of the vibrational measurement time-domain data to gas molecular weight based on the vibrational resonant frequencies.
  • a suitable wired or wireless communications link may provide a medium of communication between the processing circuitry and the sensing module.
  • the communications link may be an electromagnetic device of suitable frequency, or other methods including acoustic communication and like devices.
  • FIG. 6 illustrates an embodiment of the present disclosure whereby a gas molecular weight sensing module is utilized in a wireline application.
  • a sampling tool 600 includes a sensing module as described herein, and is shown positioned along wellbore 604 .
  • Sampling tool 600 has been suspended along formation layers 606 by a cable 602 having conductors for transporting power to sampling tool 600 and telemetry to/from sampling tool 600 and the surface.
  • the sampling tool 600 is utilized for formation fluid sampling and the inlet flow line (not shown) will provide pumpout service first to the gas sensing module.
  • the gas sensing module acquires the vibrational measurements utilized to determine the gas molecular weight in-situ as described herein.
  • the vibrational measurement signals could be saved to a memory disk onboard sampling tool 600 and processed in-situ using circuitry onboard tool 600 , or transmitted to the surface via cable 602 for well site processing.
  • a logging facility 608 collects measurements from sampling tool 600 , and may include circuitry 610 for processing and storing the measurements received from the sensing module of tool 600 .
  • the gas molecular weight sensing modules described herein provide a number of advantages.
  • First, for example, the venturi design and vibrating tube provides highly-sensitive gas molecular weight analysis that solves low gas sensitivity issues suffered by conventional tools.
  • Second, use of the venturi design allows removal desired quantities of low-density hydrocarbon liquid mixtures via manipulation of the pressure and temperature.
  • Third, the ability to pre-set differential operating temperatures of the gas sensors mitigates thermal-drifting and thereby alleviates the need for much of the maintenance and calibration necessary with conventional tools.
  • the gas sensing modules may be utilized in a variety of applications, such as, for example, openhole wireline logging or drilling services, or for permanent gas well production control and optimization.
  • a method to determine gas molecular weight of wellbore formation fluid comprising receiving wellbore formation fluid into a sensing module comprising a first sensor comprising a tube and a second sensor comprising a tube; vibrating the tubes of the first and second sensors; communicating the wellbore formation fluid through the first and second vibrating tubes; acquiring vibrational measurements of the wellbore formation fluid flowing through the vibrating tubes; and utilizing the vibrational measurements to determine the gas molecular weight of the wellbore formation fluid.
  • acquiring the vibrational measurements comprises acquiring a first resonant frequency of the vibrating tube of the first sensor as the wellbore formation fluid flows therethrough; acquiring a second resonant frequency of the vibrating tube of the second sensor as the wellbore fluid flows therethrough; acquiring temperature and pressure measurements of the wellbore formation fluid; and utilizing a differentiation between the first and second resonant frequencies to determine a gas density measurement of the wellbore formation fluid.
  • vibrating the tubes comprises activating an excitation mechanism positioned on the tubes.
  • a method to determine gas molecular weight of wellbore formation fluid comprising receiving a wellbore formation fluid into a sensing module comprising a tube; vibrating the tube; communicating the wellbore formation fluid into the vibrating tube; acquiring vibrational measurements of the wellbore fluid flowing through the vibrating tube; and utilizing the vibrational measurements to determine the gas molecular weight of the wellbore fluid.
  • a method as defined in paragraph 12, wherein acquiring the vibrational measurements comprises simultaneously acquiring a gas density measurement, temperature measurement, and pressure measurement of the wellbore fluid.
  • vibrating the tube comprises activating an excitation mechanism positioned on the tube.
  • the sensing module comprises a first and second gas sensor, each of the first and second gas sensors comprising a tube; vibrating the tube comprises vibrating the tubes of the first and second sensors; communicating the wellbore fluid into the vibrating tube comprises: communicating the wellbore formation fluid into the vibrating tube of the first sensor; and communicating the wellbore formation fluid into the vibrating tube of the second sensor; acquiring vibrational measurements of the wellbore fluid comprises: acquiring temperature and pressure measurements of the wellbore fluid traveling through the vibrating tube of the first sensor; acquiring a first gas density measurement of the wellbore fluid traveling through the vibrating tube of the first sensor; acquiring temperature and pressure measurements of the wellbore fluid traveling through the vibrating tube of the second sensor; and acquiring a second gas density measurement of the wellbore fluid traveling through the vibrating tube of the second sensor; and determining the gas molecular weight of the wellbore fluid is achieved using a differentiation of the first and second gas density measurements.
  • the sensing module comprises a first and second gas sensor arranged in series configuration with relation to one another, the first and second sensors each comprising a tube; vibrating the tube comprises vibrating the tubes of the first and second sensors; communicating the wellbore formation fluid into the vibrating tube comprises: communicating the wellbore formation fluid into the vibrating tube of the first sensor; and communicating the wellbore formation fluid into the vibrating tube of the second sensor; acquiring vibrational measurements of the wellbore formation fluid comprises: acquiring inlet temperature and pressure measurements of the wellbore fluid entering the first sensor; acquiring a first gas density measurement of the wellbore fluid as the wellbore fluid travels through the vibrating tube of the first sensor; acquiring a second gas density measurement of the wellbore fluid as the wellbore fluid travels through the vibrating tube of the second sensor; and acquiring outlet temperature and pressure measurements of the wellbore formation fluid exiting the second sensor; and determining the gas molecular weight of the wellbore formation fluid is achieved using a
  • the sensing module comprises a first and second sensor arranged in parallel configuration with relation to one another, the first and second sensors each comprising a tube; vibrating the tube comprises vibrating the tubes of the first and second sensors; communicating the wellbore formation fluid into the vibrating tube comprises: communicating the wellbore fluid into the vibrating tube of the first sensor; and communicating the wellbore formation fluid into the vibrating tube of the second sensor; acquiring vibrational measurements of the wellbore formation fluid comprises: acquiring inlet temperature and pressure measurements of the wellbore formation fluid entering the first sensor; acquiring inlet temperature and pressure measurements of the wellbore formation fluid entering the second sensor; acquiring a first gas density measurement of the wellbore formation fluid as the wellbore formation fluid flows through the vibrating tube of the first sensor; acquiring a second gas density measurement of the wellbore formation fluid as the wellbore fluid flows through the vibrating tube of the second sensor; acquiring outlet temperature and pressure measurements of the wellbore fluid exiting the first sensor; and
  • communicating the wellbore formation fluid into the vibrating tube comprises utilizing a coalesce filter to remove particles from the wellbore formation fluid before communicating the wellbore formation fluid into the vibrating tube.
  • communicating the wellbore formation fluid into the vibrating tube comprises utilizing a low-density PTFE or high-density polyethylene filter to separate gas/liquid phases of the wellbore formation fluid before communicating the wellbore formation fluid into the vibrating tube.
  • a sensing module to determine gas molecular weight of wellbore formation fluid comprising: a first sensor comprising a vibrating tube through which wellbore formation fluid may flow; and a vibrational excitation mechanism positioned on the tube; and a second sensor comprising a vibrating tube through which wellbore fluid may flow; and a vibrational excitation mechanism positioned on the tube.
  • sensing module as defined in any of paragraphs 24-31, wherein the sensing module further comprises a flow inlet coupled to the venturi inlet of the first sensor; and a flow outlet coupled to the venturi outlet of the second sensor.
  • sensing module as defined in any of paragraphs 24-33, wherein the sensing module further comprises a flow inlet coupled to the venturi inlets of the first and second sensors; and a flow outlet coupled to the venturi outlets of the first and second sensors.
  • sensing module as defined in any of paragraphs 24-35, wherein the sensing module forms part of a downhole assembly.

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