WO2013126388A1 - Détection précoce d'à-coup de pression dans un puits de pétrole et de gaz - Google Patents

Détection précoce d'à-coup de pression dans un puits de pétrole et de gaz Download PDF

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Publication number
WO2013126388A1
WO2013126388A1 PCT/US2013/026832 US2013026832W WO2013126388A1 WO 2013126388 A1 WO2013126388 A1 WO 2013126388A1 US 2013026832 W US2013026832 W US 2013026832W WO 2013126388 A1 WO2013126388 A1 WO 2013126388A1
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WIPO (PCT)
Prior art keywords
temperature
acoustic
borehole
acoustic velocity
borehole fluid
Prior art date
Application number
PCT/US2013/026832
Other languages
English (en)
Inventor
Rocco Difoggio
Daniel Duncan Blue
Original Assignee
Baker Hughes Incorporated
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US13/401,503 external-priority patent/US9109433B2/en
Application filed by Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Publication of WO2013126388A1 publication Critical patent/WO2013126388A1/fr

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Classifications

    • 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
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements
    • 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
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means

Definitions

  • This disclosure relates generally to oil and gas well logging tools. More particularly, this disclosure relates to tools and methods for identifying the influx of gas into the borehole in real-time during drilling operations.
  • Exploration for hydrocarbons commonly includes using a bottomhole assembly including a drill-bit for drilling a borehole in an earth formation.
  • Drilling fluid or "mud” used in the drilling may vary in density or "mud weight” for a number of reasons. Such variations can result from changes in the quantity and density of cuttings (particles of formation); changes in the "mud program" at the surface, changes in temperature, etc.
  • Pressure detection concepts are especially important in drilling. Not only does the drilling rate decrease with a high overbalance of mud pressure versus formation pressure, but also lost circulation and differential pressure sticking of the drill pipe can readily occur. More importantly, an underbalance of mud pressure versus formation pressure can cause a pressure "kick." A well may kick without forewarning. Balanced drilling techniques often require only a fine margin between effective pressure control and a threatened blowout. Additionally, there are situations where underbalance is maintained to avoid formation damage so that it is important to detect inflow of formation liquids into the borehole.
  • Some prior art techniques for detecting abnormal formation pressure are based on measurement of drilling parameters such as drilling rate, torque and drag; drilling mud parameters such as mud gas cuttings, flow line mud weight, pressure kicks, flow line temperature, pit level and pit volume, mud flow rate; shale cutting parameters such as bulk density, shale factor, volume and size of cuttings.
  • drilling parameters such as drilling rate, torque and drag
  • drilling mud parameters such as mud gas cuttings, flow line mud weight, pressure kicks, flow line temperature, pit level and pit volume, mud flow rate
  • shale cutting parameters such as bulk density, shale factor, volume and size of cuttings.
  • the present disclosure provides a method of detecting a gas influx event in a borehole fluid during drilling operations that includes: obtaining a measurement of an acoustic velocity of the borehole fluid at an acoustic sensor disposed in a borehole; obtaining a measurement of temperature of the borehole fluid at a temperature sensor disposed in the borehole; and comparing the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to detect the gas influx event.
  • the present disclosure provides an apparatus for detecting a gas influx event in a borehole fluid during drilling operation that includes: an acoustic sensor configured to obtain a measurement of an acoustic velocity of the borehole fluid; a temperature measuring device configured to obtain a measurement of a temperature of the borehole fluid; and a processor configured to compare the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to determine a gas influx event.
  • the present disclosure provides a computer-readable medium having a set of instruction stored thereon that when read by a processor enable the processor to perform a method, the method including: receiving a measurement of an acoustic velocity of a borehole fluid from an acoustic sensor disposed in a borehole; receiving a measurement of temperature of the borehole fluid from a temperature sensor disposed in the borehole; and comparing the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to detect a gas influx event.
  • FIG. 1 (Prior Art) shows a measurement- while-drilling tool suitable for use with the present disclosure
  • FIG. 2 is a cross sectional view of a measurement sub of the present disclosure
  • FIG. 3 is a detailed sectional view of the acoustic transducer in FIG. 2;
  • FIGS. 4A and 4B show exemplary signals using the acoustic transducer of FIG. 2 when the impedance of the borehole fluid is (a) close to that of the sensor plate, and (b) different from that of the sensor plate;
  • FIG. 5 (Prior Art) shows sound speed dependence on dissolved gas
  • FIG. 6 shows an embodiment of the disclosure in which a plurality of acoustic transducers are disposed along the drill collar;
  • FIG. 7 is an exemplary plot of velocity as a function of gas-oil ratio
  • FIG. 8 shows an exemplary arrangement of a transducer for measuring travel-times in the borehole fluid
  • FIG. 9A illustrates the principle of a stepped transducer
  • FIG. 9B illustrates an exemplary signal with the stepped transducer of FIG. 9A
  • FIG. 10 shows measurements of impedance at the input of a piezoelectric transducer as a function of frequency in different fluids
  • FIG. 11 (Prior Art) is an equivalent circuit of a transducer in contact with a borehole fluid;
  • FIG. 12 (Prior Art) shows the effect of bubble size on attenuation
  • FIG. 13 shows an exemplary embodiment of a drill string having various sensors usable for detecting a gas influx event using acoustic velocity and temperature measurements
  • FIGS. 14A and 14B show exemplary graphs of acoustic velocity and temperature, respectively, that may be used to determine an influx of gas into a borehole fluid;
  • FIG. 14C shows logarithmic values derived from the exemplary graphs of FIGS. 14 A and 14B;
  • FIG. 15A shows a graph of a change in acoustic velocity values over time
  • FIG. 15B shows a graph of a change in borehole fluid temperature values over time
  • FIG. 16 shows exemplary graphs of acoustic velocity and temperature over time.
  • FIG. 1 shows a schematic diagram of a drilling system 10 with a drillstring 20 carrying a drilling assembly 90 (also referred to as the bottom-hole assembly, or "BHA") conveyed in a "wellbore" or “borehole” 26 for drilling the wellbore.
  • the drilling system 10 includes a conventional derrick 11 erected on a floor 12 which supports a rotary table 14 that is rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed.
  • the drillstring 20 includes a tubing such as a drill pipe 22 or a coiled-tubing extending downward from the surface into the borehole 26. The drillstring 20 is pushed into the wellbore 26 when a drill pipe 22 is used as the tubing.
  • a tubing injector such as an injector (not shown), however, is used to move the tubing from a source thereof, such as a reel (not shown), to the wellbore 26.
  • the drill bit 50 attached to the end of the drillstring breaks up the geological formations when it is rotated to drill the borehole 26.
  • the drillstring 20 is coupled to a drawworks 30 via a Kelly joint 21, swivel 28, and line 29 through a pulley 23.
  • the drawworks 30 is operated to control the weight on bit, which is an important parameter that affects the rate of penetration.
  • the operation of the drawworks is well known in the art and is thus not described in detail herein.
  • a suitable drilling fluid 31 from a mud pit (source) 32 is circulated under pressure through a channel in the drillstring 20 by a mud pump 34.
  • the drilling fluid passes from the mud pump 34 into the drillstring 20 via a desurger (not shown), fluid line 38 and Kelly joint 21.
  • the drilling fluid 31 is discharged at the borehole bottom 51 through an opening in the drill bit 50.
  • the drilling fluid 31 circulates uphole through the annular space 27 between the drillstring 20 and the borehole 26 and returns to the mud pit 32 via a return line 35.
  • the drilling fluid acts to lubricate the drill bit 50 and to carry borehole cutting or chips away from the drill bit 50.
  • a sensor Si typically placed in the line 38 provides information about the fluid flow rate.
  • a surface torque sensor S 2 and a sensor S 3 associated with the drillstring 20 respectively provide information about the torque and rotational speed of the drillstring.
  • a sensor (not shown) associated with line 29 is used to provide the hook load of the drillstring 20.
  • the drill bit 50 is rotated by only rotating the drill pipe 22.
  • a downhole motor 55 (mud motor) is disposed in the drilling assembly 90 to rotate the drill bit 50 and the drill pipe 22 is rotated usually to supplement the rotational power, if required, and to effect changes in the drilling direction.
  • the mud motor 55 is coupled to the drill bit 50 via a drive shaft (not shown) disposed in a bearing assembly 57.
  • the mud motor rotates the drill bit 50 when the drilling fluid 31 passes through the mud motor 55 under pressure.
  • the bearing assembly 57 supports the radial and axial forces of the drill bit.
  • a stabilizer 58 coupled to the bearing assembly 57 acts as a centralizer for the lowermost portion of the mud motor assembly.
  • a drilling sensor module 59 is placed near the drill bit 50.
  • the drilling sensor module contains sensors, circuitry and processing software and algorithms relating to the dynamic drilling parameters. Such parameters typically include bit bounce, stick-slip of the drilling assembly, backward rotation, torque, shocks, borehole and annulus pressure, acceleration measurements and other measurements of the drill bit condition.
  • a suitable telemetry or communication sub 72 using, for example, two-way telemetry, is also provided as illustrated in the drilling assembly 90.
  • the drilling sensor module processes the sensor information and transmits it to the surface control unit 40 via the telemetry system 72.
  • the communication sub 72, a power unit 78 and an MWD tool 79 are all connected in tandem with the drillstring 20. Flex subs, for example, are used in connecting the MWD tool 79 in the drilling assembly 90. Such subs and tools form the bottom hole drilling assembly 90 between the drillstring 20 and the drill bit 50.
  • the drilling assembly 90 makes various measurements including the pulsed nuclear magnetic resonance measurements while the borehole 26 is being drilled.
  • the communication sub 72 obtains the signals and measurements and transfers the signals, using two-way telemetry, for example, to be processed on the surface. Alternatively, the signals can be processed using a downhole processor in the drilling assembly 90.
  • the surface control unit or processor 40 also receives signals from other downhole sensors and devices and signals from sensors S 1 -S3 and other sensors used in the system 10 and processes such signals according to programmed instructions provided to the surface control unit 40.
  • the surface control unit 40 displays desired drilling parameters and other information on a display/monitor 42 utilized by an operator to control the drilling operations.
  • the surface control unit 40 typically includes a computer or a microprocessor- based processing system, memory for storing programs or models and data, a recorder for recording data, and other peripherals.
  • the control unit 40 is typically adapted to activate alarms 44 when certain unsafe or undesirable operating conditions occur.
  • FIG. 2 a cross-section of an acoustic sub that can be used for determining the formation density is illustrated.
  • the drill collar is denoted by 103 and the borehole wall by 101.
  • An acoustic transducer assembly 107 is positioned inside the drill collar.
  • the acoustic transducer assembly includes an fluid- filled cavity 109.
  • An acoustic transducer 111 such as a piezoelectric transducer is positioned at one side of the cavity 109.
  • On the other side of the cavity 109 is a sensor plate 115.
  • the cavity is filled with a fluid with known density and compressional wave velocity.
  • the plate 1 15 has a known thickness, compressional wave velocity and density.
  • FIG. 3 activation of the transducer generates acoustic waves in the fluid.
  • Exemplary raypaths resulting from the excitation are shown in FIG. 3.
  • the ray path 117 corresponds to an acoustic wave that is reflected from the inner wall of the sensor plate.
  • the raypath 121 corresponds to an acoustic wave that is reflected from the outer surface of the sensor plate while raypath 119 corresponds to a wave that passes into the borehole fluid in the annulus between the BHA and the borehole wall.
  • the transducer 111 is provided with an absorptive backing 113 with an impedance that closely matches that of the transducer so as to reduce reflections from the back side of the transducer.
  • a single transducer acts as both a transmitter and as a receiver, though this is not to be construed as limitation to the disclosure: separate acoustic transmitters and receivers may be used.
  • the present disclosure relies on the signals recorded by excitation of the transducer as an indication of gas in the borehole fluid. Free gas in the borehole fluid has three main effects on the acoustic properties of the fluid. The first effect is a reduction in density of the fluid. A more important effect is the dramatic reduction in the bulk modulus of the fluid (and hence the acoustic velocity). This is the phenomenon that is the basis for the so-called "bright spot" effect in hydrocarbon exploration wherein the presence of gas in a reservoir can produce strong reflections on seismic data.
  • the average compressibility (the reciprocal of bulk modulus which is linearly related to the square of the acoustic velocity) is obtained by a weighted average of the compressibilities of the two fluids.
  • the third effect that may be observed is the attenuation of the wave that actually propagates into the borehole and may be reflected by the borehole wall.
  • an objective of the disclosure is to determine the pressure kicks before gas comes out of solution in the borehole fluid.
  • Invasion of formation fluids into the borehole is usually the result of the formation pore pressure exceeding the fluid pressure in the borehole. This may be a harbinger of a blowout and remedial action is necessary. Due to the difference in the density and P-wave velocity of the borehole mud and the density and P-wave velocity of formation fluid, this influx is detectable. Specifically, the effect of invasion is to lower the bulk modulus and density of the fluid in the borehole. This translates into a change in the impedance (and the velocity) of the mud.
  • FIG. 5 shows representative examples of sound speed (ordinate) versus amount of dissolved gas (abscissa) using a model proposed by Batzle et al.
  • the Batzle equations were intended for formation brines and crude oils, for water based muds and for oil based muds they should provide the same trends in sound speed with increasing dissolved gas.
  • the model of Batzle et al. may be used with appropriate parameters for drilling fluid, live oil (oil with dissolved gas) and dead oil. This is not to be construed as a limitation of the present disclosure and other models for predicting the elastic properties of fluid mixtures may be used.
  • Han & Batzle shows correlations of velocity and density to API gravity, Gas-Oil Ratio (GOR), Gas gravity and in situ pressure and temperatures.
  • GOR Gas-Oil Ratio
  • This is an example of another model that may be used with the method of the present disclosure.
  • the empirical cross-plots may be stored in the form of a table and a table lookup performed to determine the presence of gas in the borehole fluid.
  • Such a model may also be used for predicting the properties of a mixture of drilling mud and formation fluid. The net result of a fluid influx is to change the impedance of the borehole fluid.
  • polymethlypentene (tradenamed TPX, which is made by Mitsui) that has an acoustic impedance of 1840 kRayls.
  • Pyro lytic graphite (6 480 kRayls depending on orientation) from GE Advanced Ceramics is a good candidate.
  • titanium about 24 000 kRayls
  • aluminum about 15 800 kRayls
  • the inside face of the plate is in contact with oil in a pressure-balanced enclosure, with known acoustic characteristics. Incoming water oil or gas is expected to lower the acoustic impedance markedly. The instrument takes a reading every second and stores it in memory for 2 hours.
  • the instrument if it observes a change in acoustic impedance of 10% or more during a 2 minute interval from the extrapolated value of the preceding hour then it sends a high priority alarm and a series of informative values of the acoustic impedance from say intervals of 20 seconds preceding the alarm.
  • a 10% change in acoustic impedance is for exemplary purposes only and other criteria could be used for sending an alarm.
  • FIG. 6 Another embodiment of the disclosure is illustrated in FIG. 6.
  • the BHA 205 is provided with a transducer arrangement 209 of the type discussed above and additional transducer assemblies 211, 213, 215, 217, 219 are disposed along the drill collar 221. These are in electrical communication with each other and with a processor at the surface using wired-pipe telemetry (though other telemetry methods may be used).
  • the impedance of the mud is estimated by determining the Q of the resonant plate.
  • the velocity of P-waves in the mud may be measured using, for example, the apparatus described in U.S. Patent Application Ser. No. 10/298,706 of Hassan et al, having the same assignee as the present disclosure and the contents of which are incorporated herein by reference.
  • FIG. 7 shows velocity for a gas-oil mixture.
  • the gas remains in solution over a wide range of saturations.
  • Those versed in the art would recognize that direct measurements of velocity using pulse transmission measurements are difficult in the presence of bubbles. This means that in oil-based muds, it would be easier to measure the acoustic velocity over a wide range of gas saturation than for water-based mud.
  • DiFoggio discloses an arrangement for measuring fluid velocities in a sample chamber on a BHA or a wireline assembly.
  • a transducer assembly is positioned on the outside of the drill collar. This is illustrated in FIG. 8 which shows a borehole 26 in an earth formation 801.
  • the acoustic sensor assembly 803 is on the outside of the drillstring 805 so as to measure the acoustic velocity of mud in the annulus 807.
  • the acoustic sensor assembly 803 is shown in more detail in FIG. 9A.
  • the acoustic sensor assembly 803 comprises a transducer 901 and a stepped reflector 903.
  • the stepped refiector includes a protruding portion 905 and a recessed portion 907 that is a distance "d" further away from the transmitter than is the protruding portion.
  • the transmitter generates an acoustic pulse depicted by 909.
  • the stepped reflector 903 produces two signals.
  • the reflected signal received by the transducer 901 is shown in FIG. 9B.
  • the first arrival 951 is a result of the reflection of the pulse 909 at the protruding portion 905 of the reflector.
  • the second signal 953 is a result of the reflection of the acoustic pulse 909 at the recessed portion 907 of the reflector.
  • the depth of the recess d and the time difference between the two arrivals ⁇ gives the velocity of the acoustic pulse in the mud.
  • an autocorrelation of the received signal is performed and a peak value of the autocorrelation gives the travel time.
  • a cross-correlation of two different windows of the received signal is used, the two different windows being selected based on an expected arrival time for the acoustic pulse in order to avoid spurious aliasing. The more closely spaced the time channels for collecting the received signal, the better that the travel time resolution will be. To obtain sub-channel resolution, we interpolated the peak position between time channels.
  • the conceptual basis for sub-channel resolution is to fit a polynomial to the autocorrelation function in the neighborhood of the peak and then to find the zero crossing (the root) of the first derivative of that polynomial, which is the interpolated peak position. Because the time channels were uniformly spaced, we were able to use the computationally-simple Savitzky Go lay method to compute the first derivative, f, of the fitting polynomial at two time steps (the one just left and the one just right of the peak), and then to perform linear interpolation of the first derivative to obtain its zero crossing, which is the interpolated peak position, x P .
  • Such a precision may be hard to achieve in a borehole environment due to the attenuative and dispersive nature of the signals in mud.
  • a second cause of dispersion and attenuation is the presence of gas bubbles. Elastic theory predicts that as long as concentration of gas bubbles is low and the gas bubbles are much smaller than a quarter of the wavelength of the acoustic pulses, the reflections of the acoustic pulse would still be detectable. As the concentration of gas bubbles increases and their size increases, no reflected signals would be detectable.
  • the estimate of the travel time can be improved using deconvolution methods.
  • a Wiener deconvolution of the second arrival of the received signal is performed using, as a reference wavelet, the first arrival. See Honvarvar et al. (2008).
  • a travel time is measured for the reflection from the protruding portion of the reflector. This may be done if the reflection from the recessed portion is too weak. In such a case, the distance between the transmitter and the protruding portion of the reflector is used. A single reflection may also be used with a transducer assembly that has a flat reflector. In such situations, the estimate of the travel time may be improved using the method disclosed in DiFoggio. Specifically, the raw amplitude data can be first processed by applying a digital bandpass filter to reject any frequencies that are not close to the acoustic source frequency.
  • the first derivative of CCS generates a series of Gaussian- looking peaks.
  • the second derivative of the CSS are the first derivatives of the Gaussian peaks, whose zero crossings (roots) represent the interpolated peak positions. Smoothing the data and the utilization of the Savitzky-Golay method helps to reduce noise from the desired signal.
  • FIG. 11 is an equivalent circuit of a transducer in contact with a borehole fluid, discussed in U.S. Patent Application Ser. No. 11/447,746 of Dubinsky et al, having the same assignee as the present application.
  • the power source E g ( ) Re
  • E g (a>t) exp(jcot) is denoted by 1161, while the interaction of the transducer with the fluid is represented by a parallel RLC load circuit 1165.
  • ⁇ ⁇ ⁇ ⁇ , ⁇ 2 , ⁇ 3 , ...
  • ⁇ 1 ⁇ ⁇ , ⁇ 2 , ⁇ 3 ,...
  • FIG. 10 shows actual measurements of the impedance of an exemplary piezoelectric transducer at different frequencies.
  • the curves 1001 and 1003 are the real (in- phase) impedance for a transducer immersed in soda (containing dissolved C02 but no visible bubbles) and in water respectively.
  • the imaginary (out-of-phase) impedance could also be plotted.
  • the narrow bandwidth of the resonance for the soda curve 1001 is a result of a high quality factor Q of the sensor due to the low impedance of the soda water at that frequency. This experiment could be repeated under pressure to insure that all bubbles, including those that might be too small to see, have been crushed.
  • FIG. 12 data are shown of the effect of air bubbles on acoustic signals propagating through water. These measurements were made at frequencies of up to 1 kHz.
  • the curve 1201 corresponds to a bubble radius of .002 ft (.61mm) and the curve 1203 to a bubble radius of .014 ft (4.27mm).
  • the abscissa is the frequency and the ordinate is the product of attenuation and sound velocity, i.e., the attenuation in dB per second.
  • the lower frequency measurements generally show lower attenuation, but the attenuation increases rapidly as a resonance frequency 1205 is approached.
  • OBM oil-based-mud
  • Pulse transmission techniques may be used, and generally give a more precise estimate of gas saturation than do impedance measurements. Above the bubble point, pulse transmission techniques have some difficulty in getting measurable signals.
  • WMB water-based-mud
  • Impedance measurements while less precise, can give estimates of gas saturation above bubble point. With either method, it is important to monitor the gas saturation during drilling operations. When no detectable reflection, or a severely attenuated reflection is received by the transducer, this is referred to as a null output and the processor indicates the presence of bubbles in the fluid. The margin of safety is somewhat larger for OBM.
  • FIG. 13 shows an exemplary embodiment of a drill string 805 having various sensors usable for detecting a gas influx event using acoustic velocity and temperature measurements.
  • the drill string includes the drill bit 50, an acoustic sensor 803 comprising an acoustic transducer and a stepped acoustic reflector, and at least one temperature sensor 1301A-C.
  • the drill string may further include a processor such as discussed with respect to FIG. 1 that is configured to receive measurements obtained at the acoustic sensor and the temperature sensor and to detect the gas influx event using the received measurements and the methods discussed herein.
  • the acoustic sensor measures the acoustic velocity of the fluid in the annulus 807.
  • the temperature sensor measures the temperature of the fluid in the annulus 807.
  • the acoustic sensor and the temperature sensor may be disposed at a location suitable for measuring acoustic velocity and temperature of the borehole fluid in the annulus between the drill string 805 and the borehole wall 26.
  • the temperature sensor such as temperature sensor 1301 A is disposed at substantially the same axial location of the drill string as the acoustic sensor 803.
  • the temperature sensor may be disposed within the drill bit 50 such as temperature sensor 130 IB or proximate the drill bit 50 such as temperature sensor 1301C.
  • the presence of gas from a gas influx event causes a change in an acoustic velocity of the borehole fluid as well as a change in a temperature of the borehole fluid.
  • a measured change in a temperature of the borehole fluid may be used to confirm a gas influx event that is detected using a measured change in the acoustic velocity of the borehole fluid.
  • FIGS. 14A and 14B show exemplary graphs of acoustic velocity and temperature, respectively, that may be used to determine an influx of gas into a borehole fluid.
  • the acoustic velocity changes from about 1270 m/sec to about 1240 m/sec.
  • the temperature of the borehole fluid changes from a first temperature to a second temperature when the gas enters the borehole fluid.
  • the temperature changes from about 136.20°C to about 136.05°C.
  • the changes are shown as a drop in the values of the measured properties, the changes can also include rises in these values. If the acoustic sensor and the temperature sensor are placed at the same locations, these changes may be detected at substantially the same time. If the acoustic sensor and the temperature sensor are placed at separate locations, then the changes may be detected at different times. However, the time difference can be removed by shifting the graph of the temperature with respect to the graph of the acoustic velocity by a determinable amount.
  • FIG. 14C shows logarithmic values derived from the exemplary graphs of FIGS. 14A and 14B.
  • Curve 1401A is a logarithm of the acoustic velocity values of FIG. 14A and curve 1401B is a logarithm of the temperature values of FIG. 14B.
  • Curve 1403 is a difference between curve 1401 A and curve 1401B.
  • the substantially constant value of curve 1403 indicates that the acoustic velocity and the temperature are changing at substantially the same rate and therefore that the changes in the acoustic velocity and in the temperature result from the same effect, i.e., a gas influx event.
  • the temperature curve can be subtracted from a constant temperature value to produce a complementary temperature curve.
  • This complementary temperature curve declines with time similar to the decline of the acoustic velocity curve with time shown in FIG. 14B.
  • FIG. 15A shows a graph of a derivative of acoustic velocity values against time.
  • FIG. 15B shows a graph of a derivative of borehole fluid temperature values against time.
  • the gas influx event is confirmed by having both the acoustic velocity and temperature crosses over these selected threshold values.
  • the exemplary graphs indicate the occurrence of the gas influx event when graphs 1501 and 1503 drop below the threshold value, an alternate graph can be used in which one or more graphs rise above a selected value to indicate the gas influx event.
  • FIG. 16 shows an exemplary graph of acoustic velocity vs. time and an associated exemplary graph of temperature vs. time displaying a number of gas influx events.
  • Acoustic velocity spikes 1601 - 1604 occur at times ti-t 6 , respectively.
  • temperature spikes 1611-1614 occur at times ti-t 6 , respectively.
  • a spike in the acoustic velocity occurs simultaneously with a spike in the temperature when they result from a same event.
  • the height of each spike may be compared to a selected threshold value to indicate the presence of gas.
  • acoustic velocity spikes 1601 and 1602 are greater than a selected acoustic velocity threshold value and temperature spikes 1611 and 1612 are greater than a selected temperature threshold value.
  • a gas influx event is confirmed at times ti and t 2 .
  • spikes 1603 and 1613 are not greater than their respective threshold values, and thus no gas influx event is detected at t 3 .
  • Acoustic velocity spike 1604 is greater than the acoustic velocity threshold, but corresponding temperature spike 1614 is not greater than the temperature threshold value. Therefore, a gas influx event is not detected at t 4 .
  • acoustic velocity and temperature measurements are obtained at time intervals close enough to provide a sufficient resolution to record the spikes of FIG. 16. The height of the spikes may be determined by comparing values over several time intervals.
  • the processing of the data may be accomplished by a downhole processor and/or a processor at the surface.
  • measurements may be stored on a suitable memory device and processed upon retrieval of the memory device for detailed analysis.
  • Implicit in the control and processing of the data is the use of a computer program on a suitable machine readable medium that enables the processor to perform the control and processing.
  • the machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. All of these media have the capability of storing the data acquired by the logging tool and of storing the instructions for processing the data. It would be apparent to those versed in the art that due to the amount of data being acquired and processed, it is impossible to do the processing and analysis without use of an electronic processor or computer.
  • the present disclosure provides a method of detecting a gas influx event in a borehole fluid during drilling operations that includes: obtaining a measurement of an acoustic velocity of the borehole fluid at an acoustic sensor disposed in a borehole; obtaining a measurement of temperature of the borehole fluid at a temperature sensor disposed in the borehole; and comparing the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to detect the gas influx event.
  • the gas influx event is detected when a change in the acoustic velocity exceeds a selected acoustic velocity threshold and a change in the temperature exceeds a selected temperature threshold.
  • the measurement of acoustic velocity of the borehole fluid is obtained by generating an acoustic pulse in the borehole fluid at a downhole location; reflecting the generated acoustic pulse from at least two reflecting surfaces of a stepped reflector in the fluid to provide at least two reflected pulses; and determining the acoustic velocity of the borehole fluid from a difference in arrival time of the at least two reflected pulses.
  • the method may further include providing a logarithmic plot of the acoustic velocity versus time and to a logarithmic plot of the temperature (or of the complementary temperature) versus time.
  • the method may alternatively include comparing a first derivative of the acoustic velocity to a selected threshold value and comparing a first derivative of the temperature to a selected threshold value.
  • the acoustic sensor and the temperature sensor are disposed in an annulus between a drill string and a borehole wall.
  • the temperature sensor may be disposed at one of: (i) in a drill bit; (ii) proximate the drill bit; and (iii) proximate a bottomhole assembly.
  • the present disclosure provides an apparatus for detecting a gas influx event in a borehole fluid during drilling operation that includes: an acoustic sensor configured to obtain a measurement of an acoustic velocity of the borehole fluid; a temperature measuring device configured to obtain a measurement of a temperature of the borehole fluid; and a processor configured to compare the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to determine a gas influx event.
  • the processor may be further configured to detect the gas influx event when a change in the acoustic velocity exceeds a selected acoustic velocity threshold and a change in the temperature exceeds a selected temperature threshold.
  • the processor may be further configured to detect the gas influx event when the change in the acoustic velocity exceeds the selected acoustic velocity threshold and a change in the temperature exceeds the selected temperature threshold at substantially a same time.
  • the acoustic sensor includes an acoustic transducer configured to generate an acoustic pulse in the borehole fluid and to detect an acoustic signal from the borehole fluid and a stepped reflector configured to provide at least two reflections of the generated acoustic pulse to the acoustic transducer.
  • the processor may further compare a logarithmic plot of the acoustic velocity to a logarithmic plot of the temperature versus time.
  • the processor may compare a first derivative of the acoustic velocity to a selected threshold value and compare a first derivative of the temperature to a selected threshold value.
  • the acoustic velocity sensor and the temperature sensor are disposed in an annulus between the drill string and borehole wall.
  • the temperature sensor may be disposed at one of : (i) in a drill bit; (ii) proximate the drill bit; and (iii) proximate a bottomhole assembly.
  • the present disclosure provides a computer-readable medium having a set of instruction stored thereon that when read by a processor enable the processor to perform a method, the method including: receiving a measurement of an acoustic velocity of a borehole fluid from an acoustic sensor disposed in a borehole; receiving a measurement of temperature of the borehole fluid from a temperature sensor disposed in the borehole; and comparing the measurement of the acoustic velocity of the borehole fluid to the measurement of the temperature of the borehole fluid to detect a gas influx event.

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  • Physics & Mathematics (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geophysics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Acoustics & Sound (AREA)
  • Investigating Or Analyzing Materials By The Use Of Ultrasonic Waves (AREA)
  • Geophysics And Detection Of Objects (AREA)

Abstract

L'invention concerne un appareil, un procédé et un support lisible par ordinateur pour détecter un événement de flux d'entrée de gaz dans un fluide de trou de forage pendant une opération de forage. On obtient une mesure de vitesse acoustique du fluide de trou de forage sur un capteur acoustique disposé dans le trou de forage, et on obtient une mesure de température du fluide de trou de forage sur un capteur de température disposé dans le trou de forage. Un procédé permet de comparer la mesure de la vitesse acoustique du trou de forage et la mesure de la température du trou de forage afin de détecter l'événement d'entrée de gaz.
PCT/US2013/026832 2012-02-21 2013-02-20 Détection précoce d'à-coup de pression dans un puits de pétrole et de gaz WO2013126388A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/401,503 2012-02-21
US13/401,503 US9109433B2 (en) 2005-08-01 2012-02-21 Early kick detection in an oil and gas well

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WO2013126388A1 true WO2013126388A1 (fr) 2013-08-29

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Cited By (8)

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Publication number Priority date Publication date Assignee Title
DE102014003552A1 (de) 2014-03-12 2015-09-17 Frank-Michael Jäger Vorrichtung und Verfahren zur frühen Erkennung von Zuflüssen in Untergrundbohrungen
US9938820B2 (en) 2015-07-01 2018-04-10 Saudi Arabian Oil Company Detecting gas in a wellbore fluid
US11332991B2 (en) 2019-07-17 2022-05-17 Saudi Arabian Oil Company Targeted downhole delivery with container
US11384612B2 (en) 2017-07-11 2022-07-12 Equinor Energy As Method and system for monitoring influx and loss events in a wellbore
RU2804085C1 (ru) * 2023-01-25 2023-09-26 Публичное акционерное общество "Нефтяная компания "Роснефть" (ПАО "НК "Роснефть") Способ определения скорости звука в затрубном пространстве скважины
US11867049B1 (en) 2022-07-19 2024-01-09 Saudi Arabian Oil Company Downhole logging tool
US11879328B2 (en) 2021-08-05 2024-01-23 Saudi Arabian Oil Company Semi-permanent downhole sensor tool
US11913329B1 (en) 2022-09-21 2024-02-27 Saudi Arabian Oil Company Untethered logging devices and related methods of logging a wellbore

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WO1998050680A2 (fr) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Surveillance de parametres et d'outils de fond de puits au moyen de fibres optiques
US20050223808A1 (en) * 2004-04-09 2005-10-13 Shell Oil Company Apparatus and methods for acoustically determining fluid properties while sampling
US20090173150A1 (en) * 2005-08-01 2009-07-09 Baker Hughes Incorporated Early Kick Detection in an Oil and Gas Well
US20090272580A1 (en) * 2008-05-01 2009-11-05 Schlumberger Technology Corporation Drilling system with drill string valves

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US5130950A (en) * 1990-05-16 1992-07-14 Schlumberger Technology Corporation Ultrasonic measurement apparatus
WO1998050680A2 (fr) * 1997-05-02 1998-11-12 Baker Hughes Incorporated Surveillance de parametres et d'outils de fond de puits au moyen de fibres optiques
US20050223808A1 (en) * 2004-04-09 2005-10-13 Shell Oil Company Apparatus and methods for acoustically determining fluid properties while sampling
US20090173150A1 (en) * 2005-08-01 2009-07-09 Baker Hughes Incorporated Early Kick Detection in an Oil and Gas Well
US20090272580A1 (en) * 2008-05-01 2009-11-05 Schlumberger Technology Corporation Drilling system with drill string valves

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DE102014003552A1 (de) 2014-03-12 2015-09-17 Frank-Michael Jäger Vorrichtung und Verfahren zur frühen Erkennung von Zuflüssen in Untergrundbohrungen
US9938820B2 (en) 2015-07-01 2018-04-10 Saudi Arabian Oil Company Detecting gas in a wellbore fluid
US11384612B2 (en) 2017-07-11 2022-07-12 Equinor Energy As Method and system for monitoring influx and loss events in a wellbore
US11332991B2 (en) 2019-07-17 2022-05-17 Saudi Arabian Oil Company Targeted downhole delivery with container
US11879328B2 (en) 2021-08-05 2024-01-23 Saudi Arabian Oil Company Semi-permanent downhole sensor tool
US11867049B1 (en) 2022-07-19 2024-01-09 Saudi Arabian Oil Company Downhole logging tool
US11913329B1 (en) 2022-09-21 2024-02-27 Saudi Arabian Oil Company Untethered logging devices and related methods of logging a wellbore
RU2804085C1 (ru) * 2023-01-25 2023-09-26 Публичное акционерное общество "Нефтяная компания "Роснефть" (ПАО "НК "Роснефть") Способ определения скорости звука в затрубном пространстве скважины

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