Mud gas ratio and mud flow velocity sensor

• US 4,208,906 A
• Filed: 05/08/1978
• Issued: 06/24/1980
• Est. Priority Date: 05/08/1978
• Status: Expired due to Term

• Current Assignee: Interstate Electronics Corp. (L3Harris Technologies, Inc.)
• Original Assignee: Interstate Electronics Corp. (L3Harris Technologies, Inc.)
• Inventors: Roberts, Liona R. Jr.
• Primary Examiner(s): Myracle, Jerry W.
• Application Number:
  US05/903,801
• Time in Patent Office: 778 Days
• Field of Search: 73/597, 73/155, 181/102, 364/422, 364/804
• US Class Current: 73/152.32
• CPC Class Codes: E21B 47/107 using acoustic means
• CPC Class Codes: E21B 49/005 Testing the nature of borehole walls or the formation by using drilling mud or cutting data
• CPC Class Codes: G01N 2291/02818 Density, viscosity
• CPC Class Codes: G01N 2291/02836 Flow rate, liquid level
• CPC Class Codes: G01N 29/024 by measuring propagation velocity or propagation time of acoustic waves

Abstract

A remote sensor for the measurement of the amount of gas present in the drilling fluid or "mud" in an offshore well-drilling operation, for the purpose of giving prompt warning of geologic conditions conducive to the occurrence of a blow-out. An acoustic projector projects an acoustic wave of fixed wavelength through the mud returning upwardly from the borehole. The wave is received by a first array of acoustic receivers locked in a known phase relationship with the projector. Changes in the speed of sound due to changing relative amounts of mud and gas produce a shift in frequency of the acoustic wave which is proportional to the speed of sound in the mud/gas mixture. The change in frequency is electronically detected and scaled to yield the value of the speed of sound, from which the mud to gas mass ratio is calculated by means of a computer. A second array of acoustic receivers is arranged with the first array and the projector to form a phase-shift velocimeter which uses the value of the speed of sound obtained in conjunction with the mud/gas mass ratio measurement to calculate the velocity of the mud flow, which is used as a further indicator of potential blowout conditions.

Claims

1. A device for the sensing of drilling fluid properties in a well-drilling operation, comprising:

a riser through which said drilling fluid passes;

acoustic projector means mounted in said riser for projecting an acoustic wave through said drilling fluid, said acoustic wave having a predetermined wavelength λ and

a frequency f;

first acoustic receiver means mounted in said riser for receiving said acoustic wave, said first acoustic receiver means having a phase center which is spaced from said acoustic projector means by a distance equal to a predetermined number of said wavelengths λ

;

means for locking said first acoustic receiver means into a predetermined phase relationship with said acoustic projector means by changing said frequency f of said acoustic wave so as to maintain said predetermined number of said wavelengths λ

in said distance when the speed of sound c through said drilling fluid changes in response to a change in the amount of gas in said drilling fluid;

metering means electronically coupled to said phase-locking means for measuring said frequency f and producing a signal;

first electronic scaling means responsive to said signal from said metering means, for calculating said speed of sound c and producing a signal indicative of said speed of sound c;

computing means responsive to said signal from said first scaling means, for calculating a ratio γ

of drilling fluid mass to gas mass, using an equation ##EQU8## where c₁ is the speed of sound in pure drilling fluid, c₂ is the speed of sound in gas, ρ

₁ is the density of pure drilling fluid, and ρ

₂ is the density of gas;

second acoustic receiver means mounted in said riser for receiving said acoustic wave, said second receiver means having a phase shift with respect to said first receiver means due to a flow velocity of said drilling fluid, said phase shift being approximately proportional to said drilling fluid flow velocity and inversely proportional to said speed of sound c through said drilling fluid;

phase detector means electronically coupled to said first and second receiver means for measuring said phase shift and producing a signal; and

second electronic scaling means, responsive to said signal from said phase detector means and said signal from said first scaling means, for calculating said drilling fluid flow velocity.

2. The device of claim 1, wherein said projector means and said first and second receiver means are electro-acoustical transducers, and said projector transducer is driven at said frequency f by a voltage-controlled oscillator.

3. The device of claim 2 wherein said phase locking means is a phase-locked loop, comprising:

said voltage-controlled oscillator;

a signal from said first receiver means;

a frequency reference signal from said voltage-controlled oscillator; and

phase detecting means for comparing the phase of said frequency reference signal with the phase of said signal from said first receiver means and producing an output signal having a voltage which is proportional to the difference in phase between said frequency reference signal and said signal from said first receiver means, said voltage-controlled oscillator responding to said output signal by shifting said frequency reference signal until said output signal has a predetermined voltage.

4. The device of claim 1, wherein said first and second receiving means each comprise a pair of vertically spaced transducers, one of said pair being a distance of (n+1/2)λ

from said projector means, and the other of said pair being a distance of (n-1/2)λ

from said projector means, where n is a predetermined number.

5. The device of claim 4, wherein said first and second receiving means are rotated 90°

on said riser from said projector means.

6. A device for measuring the amount of gas present in a drilling fluid used in drilling a well, comprising:

a riser through which said drilling fluid flows;

acoustic projector means mounted in said riser for projecting an acoustic wave through said drilling fluid, said acoustic wave having a pre-determined wavelength λ

with an associated frequency f, said wave being produced in response to an electrical input signal to said projector means;

acoustical receiver means mounted in said riser downstream from said projector means for receiving said acoustic wave and converting said wave into an electrical output signal, said receiver means having a phase center spaced from said projector means by a distance equal to a predetermined number of said wavelengths λ

;

means for locking said output signal into a predetermined phase relationship with said input signal by varying said input signal to change said frequency f of said projected acoustic wave so as to maintain said predetermined number of said wavelengths λ

in said distance when the speed of sound c through said drilling fluid changes in response to a change in the amount of gas in said drilling fluid;

metering means electronically coupled to said phase-locking means for measuring said frequency f and producing a signal;

electronic speed of sound scaling means responsive to said signal from said metering means for calculating said speed of sound c and producing a signal indicative of said speed of sound c; and

computing means responsive to said signal from said scaling means, for calculating a ratio γ

of drilling fluid mass to gas mass, using an equation ##EQU9## where c₁ is the speed of sound in pure drilling fluid, c₂ is the speed of sound in gas, ρ

₁ is the density of pure drilling fluid, and ρ

₂ is the density of gas.

7. The device of claim 6, further comprising mud flow velocity measuring means responsive to said signal from said scaling means.

8. The device of claim 7, wherein said mud flow velocity measuring means comprises:

a second acoustic receiver means mounted in said riser upstream from said projector means for receiving said acoustic wave from said projector means and producing a second output signal having a phase shift with respect to said input signal due to a flow velocity of said drilling fluid, said phase shift being approximately proportional to said flow velocity and inversely proportional to said speed of sound c;

phase detector means for measuring said phase shift and producing a signal having a voltage proportional to said phase shift; and

flow velocity scaling means responsive to said signal from said phase detector means and to said signal from said speed of sound scaling means for calculating said flow velocity.

9. A method of measuring the relative proportions of drilling fluid and gas in a mixture of drilling fluid and gas flowing upwardly in a riser from the bottom of a well, comprising the steps of:

determining the speed of sound c₁ in pure drilling fluid;

determining the speed of sound c₂ in gas;

determining the density ρ

₁ of pure drilling fluid;

determining the density ρ

₂ of gas;

measuring the speed of sound c in said mixture; and

computing a ratio γ

of drilling fluid mass to gas mass with the equation ##EQU10##

10. The method of claim 9, where said step of measuring of said speed of sound c in said mixture comprises the steps of:

projecting an acoustic wave of wavelength λ and

frequency f from an acoustic projector in said riser;

receiving said acoustic wave by an acoustic receiver located in said riser a distance which is predetermined number of said wavelengths λ

from said projector;

locking said acoustic receiver in a predetermined phase relationship with said projector by changing said frequency f of said acoustic wave so as to maintain said predetermined number of said wavelengths λ

in said distance when said speed of sound c through said mixture changes in response to a change in the amount of gas in said mixture;

measuring said frequency f which maintains said predetermined number of said wavelength λ

in said distance; and

calculating said speed of sound c by using a relationship fλ

/c=1.

11. In a well-drilling operation in which drilling fluid is pumped up and out of a bore-hole through a riser, and in which said riser has mounted therein an acoustic projector, a first acoustic receiver downstream from said projector, and a second acoustic receiver upstream from said projector, a method of measuring the amount of gas mixed with said drilling fluid and the flow velocity of said drilling fluid, comprising the steps of:

projecting an acoustic wave through said drilling fluid and gas mixture from said projector in response to an electrical input signal to said projector, said wave having a wavelength λ

, a predetermined number of which equals the distance from said projector to said first receiver, said wavelength λ

having an associated frequency f;

receiving said wave by said first and second receivers;

converting said wave into a first electrical output signal from said first receiver;

locking the phase of said first output signal into a predetermined phase relationship with the phase of said input signal by changing said frequency f of said acoustic wave so as to maintain said predetermined number of said wavelengths λ

in said distance when the speed of sound c in said drilling fluid changes in response to a change in the amount of gas in said drilling fluid and gas mixture;

measuring said frequency f which maintains said predetermined number of said wavelengths λ

in said distance;

calculating said speed of sound c by using a relationship fλ

/c=1;

computing a ratio γ

of drilling fluid mass to gas mass in said mixture with an equation ##EQU11## where c₁, c₂, ρ

₁, and ρ

₂ are pre-determined values of the speed of sound in drilling fluid, speed of sound in gas, density of drilling fluid, and density of gas, respectively;

converting said acoustic wave into a second electrical output signal from said second receiver;

measuring the difference in phase between said first output signal and said second output signal, said difference in phase being approximately proportional to the flow velocity v of said drilling fluid through said riser and inversely proportional to said speed to cound c through said drilling fluid and gas mixture; and

using the previously calculated value of the speed of sound c through the drilling fluid and gas mixture to calculate the value of said flow velocity v.

12. The method of claim 11, further comprising the steps of:

predicting future values of said ratio γ

by using a statistical estimator for said equation.

13. The method of claim 12, wherein said statistical estimator is a recursive Kalman filter estimator algorithm.

14. A method of predicting blowouts during the drilling of a well in which a drilling fluid is used, wherein the amount of gas mixed with said drilling fluid is an indicator of blowout potential, comprising the steps of:

acoustically measuring the speed of sound in said mixture of drilling fluid and gas in said well;

obtaining a best estimate of the value of the speed of sound; and

computing the mass ratio of drilling fluid to gas based upon said best estimate of the value of the speed of sound.

15. The method of claim 14, wherein said measuring step comprises the steps of:

conducting said mixture upwardly from the bottom of said well through a riser;

projecting an acoustic wave of a predetermined wavelength into said riser and the mixture flowing therein;

receiving said wave at a first location after said wave has traveled a distance equal to a predetermined number of said wavelengths;

adjusting the frequency of said projected acoustic wave so as to maintain said predetermined number of wavelengths in said distance when the speed of sound in said mixture changes in response to a change in the proportions of drilling fluid and gas in said mixture;

measuing the frequency which maintains said predetermined number of wavelengths in said distance; and

calculating the value of the speed of sound based upon the measured frequency and said predetermined wavelength.

16. The method of claim 15, further comprising the steps of:

receiving said wave at a second location;

comparing the phase of said wave received at said first and second locations;

measuring a phase shift based upon said comparison; and

computing the flow velocity of said mixture based upon said measured phase shift and said calculated value of the speed of sound.

17. The method of claim 14, wherein said best estimate is obtained by applying a statistical estimator for said measured values.

18. The method of claim 14 further comprising the step of computing the flow velocity of said mixture base upon said measured speed of sound.

19. Apparatus for computing the mass ratio of drilling fluid and gas in a well riser, comprising:

first means for acoustically measuring the speed of sound in a mixture of drilling fluid and gas in said well; and

second means responsive to said first means for computing said ratio based upon said measured speed of sound.

20. The apparatus of claim 19, further comprising third means responsive to said first means for computing the flow velocity of said mixture based upon said measured speed of sound.

21. The apparatus of claim 20, wherein said first means comprises:

projector means for projecting an acoustic wave through said mixture;

first receiver means at a first location for receiving said wave and producing a first signal; and

second receiver means at a second location for receiving said wave and producing a second signal.

22. The apparatus of claim 21, wherein said third means comprises:

means for measuring a phase shift between said first and second signals resulting from the velocity of flow of said mixture between said first and second receiver means; and

means responsive to said measuring means for calculating said velocity of flow based upon said measured value of the speed of sound and said measured phase shift.

23. The apparatus of claim 19, wherein said first means comprises:

projector means for projecting an acoustic wave into said riser and through said mixture of drilling fluid and gas therein, said wave having a predetermined wavelength;

receiver means at a distance from said projector means equal to a fixed number of said wavelengths;

frequency-varying means coupled to said projector means and said receiver means for maintaining said fixed number of wavelengths in said distance by varying the frequency of said wave as the speed of sound through said mixture changes in response to a change in the relative proportions of drilling fluid and gas in said mixture;

metering means responsive to said frequency-varying means for measuring the frequency which maintains said fixed number of wavelengths in said distance; and

electronic scaling means responsive to said metering means for calculating the speed of sound based upon said measured frequency and said predetermined wavelength.

24. The apparatus of claim 19, wherein said second means comprises:

estimator means for obtaining a best estimate among several measured values of the speed of sound; and

calculating means for computing said ratio based upon said best estimate of said measured values of the speed of sound.

25. The apparatus of claim 24, wherein said second means is a computer and said estimator means and said calculating means are computer algorithms.