WO2008024806A2 - Détection précoce de venue dans un puits de pétrole et de gaz - Google Patents

Détection précoce de venue dans un puits de pétrole et de gaz Download PDF

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Publication number
WO2008024806A2
WO2008024806A2 PCT/US2007/076463 US2007076463W WO2008024806A2 WO 2008024806 A2 WO2008024806 A2 WO 2008024806A2 US 2007076463 W US2007076463 W US 2007076463W WO 2008024806 A2 WO2008024806 A2 WO 2008024806A2
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WO
WIPO (PCT)
Prior art keywords
impedance
fluid
transducer
borehole
sensor plate
Prior art date
Application number
PCT/US2007/076463
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English (en)
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WO2008024806A8 (fr
WO2008024806A3 (fr
Inventor
Roland E. Chemali
Volker Krueger
Rocco Difoggio
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Baker Hughes Incorporated
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Publication date
Application filed by Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Publication of WO2008024806A2 publication Critical patent/WO2008024806A2/fr
Publication of WO2008024806A3 publication Critical patent/WO2008024806A3/fr
Publication of WO2008024806A8 publication Critical patent/WO2008024806A8/fr

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Classifications

    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N29/00Investigating or analysing materials by the use of ultrasonic, sonic or infrasonic waves; Visualisation of the interior of objects by transmitting ultrasonic or sonic waves through the object
    • G01N29/02Analysing fluids
    • G01N29/024Analysing fluids by measuring propagation velocity or propagation time of acoustic waves
    • EFIXED CONSTRUCTIONS
    • E21EARTH OR ROCK DRILLING; MINING
    • E21BEARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/10Locating fluid leaks, intrusions or movements
    • E21B47/107Locating fluid leaks, intrusions or movements using acoustic means
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N29/00Investigating or analysing materials by the use of ultrasonic, sonic or infrasonic waves; Visualisation of the interior of objects by transmitting ultrasonic or sonic waves through the object
    • G01N29/02Analysing fluids
    • G01N29/028Analysing fluids by measuring mechanical or acoustic impedance
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01VGEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/028Material parameters
    • G01N2291/02818Density, viscosity

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. Variations in mud density also occur when gas or liquid enter the borehole from the formation. Such influx of formation fluids may likely be the result of formation overpressures or abnormally high pressures.
  • 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. All of these suffer from the drawback that the measurements are not available in real-time as they must wait for the bottom hole fluid to reach the surface.
  • the apparatus includes a bottomhole assembly (BHA) configured to be conveyed in a borehole.
  • the BHA includes at least one transducer assembly which has a sensor plate in contact with the borehole fluid and a cavity disposed between a transducer and the sensor plate.
  • the transducer is configured to generate acoustic vibrations in the sensor plate.
  • the apparatus includes a processor configured to estimate from a signal indicative of the acoustic vibrations an impedance of the borehole fluid, and to use the estimated fluid impedance to provide an indication of the gas influx.
  • the cavity may include a fluid having a known density and compressional velocity.
  • the signal indicative of the acoustic vibrations may be provided by the transducer and/or a receiver.
  • a sensor plate may have an acoustic impedance selected to match an expected impedance of the borehole fluid.
  • the processor may be configured to estimate the impedance of the borehole fluid by determining a quality factor of the acoustic vibrations.
  • the processor may be configured to provide the indication of gas influx using a table lookup.
  • the apparatus may further include a device configured to measure a P-wave velocity in the borehole fluid, and wherein the processor may be configured to provide the indication of gas influx using a density derived from the estimated fluid impedance and the measured P-wave velocity.
  • the sensor plate may be made of a material selected from a polyamide, a polymethylpentene, pyrolitic graphite, titanium, and/or aluminum.
  • the at least one transducer assembly may include a plurality of transducer assemblies in electrical communication.
  • One embodiment of the present disclosure is a method of detecting a gas influx from the formation during drilling of a borehole.
  • the method includes conveying a BHA including at least one transducer assembly into the borehole.
  • a transducer on a first side of the cavity in the transducer assembly is used to generate acoustic vibrations in a sensor plate on a second side of the cavity, the sensor plate being in contact with the borehole fluid.
  • the method further includes estimating from a signal indicative of the acoustic vibrations an impedance of the borehole fluid, and using the estimated fluid impedance to provide an indication of the gas influx.
  • the method may further include having a fluid with a known density and knowing compressional velocity in the cavity.
  • the signal indicative of the acoustic vibrations may be provided using the transducer and/or a receiver.
  • the method may further include selecting a material for the sensor plate that has an acoustic impedance which matches an expected impedance of the borehole fluid. Estimation of the impedance of the borehole fluid may be done by determining a quality factor of the acoustic vibrations. A table lookup may be used to provide the indication of gas influx.
  • the method may further include measuring a P-wave velocity in the borehole fluid, and providing the indication of gas influx may further use a density derived from the estimated fluid impedance and the measured P-wave velocity.
  • the method may further include electing a material for the sensor plate from a polyamide, a polymethylpentene, pyrolitic graphite, titanium, and/or aluminum.
  • the method may further include providing an abosrptive backing on a backside of the transducer to reduce reflections.
  • a plurality of transducer assemblies in electrical communication may be used.
  • Providing the indication of gas influx may further include providing an alarm signal when the estimated fluid impedance changes by more than a specified threshold value relative to the estimated fluid impedance in an earlier interval.
  • Another embodiment of the disclosure is a computer readable medium for use with an apparatus for detecting a gas influx from the formation during drilling of a borehole.
  • the apparatus includes a bottomhole assembly configured to be conveyed in a borehole, a transducer assembly on the BHA that includes a sensor plate in contact with the borehole fluid, and a cavity between a transducer and the sensor plate, the transducer being configured to generate acoustic vibrations in the sensor plate.
  • the medium includes instructions that enable a processor to estimate from a signal indicative of the acoustic vibrations an impedance of the borehole fluid, and use the estimated fluid impedance to provide an indication of the gas influx.
  • the medium may include a ROM, an EPROM, a flash memory and/or an optical disk
  • 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 Figure 2;
  • FIGS. 4a and 4b show exemplary signals using the acoustic transducer of
  • FIG. 5 shows modeled bulk moduli of fluid mixtures as a function of density using a model of Batzle & Wang as calculated in the thesis of Terra
  • FIG. 6 shows an embodiment of the disclosure in which a plurality of acoustic transducers are disposed along the drill collar.
  • 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 -S 3 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 115 has a known thickness, compressional wave velocity and density.
  • 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 of the mud.
  • Fig. 5 shows an example of a cross-plot of modeled bulk modulus versus density for a three phase mixture.
  • the example is from Bulloch (Michigan Technological University M.S. Thesis) using a model proposed by Batzle et al.
  • the curve 191 is for an oil-water mixture for different fluid saturations
  • the curve 193 is for a three phase mixture of oil, water and gas
  • the curve 195 is for a gas-water mixture.
  • 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 Raio (GOR), Gas gravity and in situ pressure and temperatures.
  • GOR Gas-Oil Raio
  • 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.
  • Pyrolytic 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.
  • the use of 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.
  • 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 US Patent Application Ser. No. 10/298706 of Hassan et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference.
  • the density can be determined. The density may be a better indication of a potential gas kick than impedance or velocity separately.
  • the processing of the data may be accomplished by a downhole processor.
  • 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.

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

Abstract

Selon la présente invention, un transducteur acoustique sur un outil de fond envoie une onde acoustique à travers une plaque de capteur qui est en contact avec un fluide de forage. Des vibrations de la plaque de capteur indiquent l'impédance de la plaque de forage qui peut être associée à une arrivée de gaz. Un processeur analyse les vibrations et utilise une évaluation de Q des vibrations pour déterminer l'arrivée de gaz.
PCT/US2007/076463 2006-08-23 2007-08-22 Détection précoce de venue dans un puits de pétrole et de gaz WO2008024806A2 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US83960206P 2006-08-23 2006-08-23
US60/839,602 2006-08-23
US11/841,527 2007-08-20
US11/841,527 US20080047337A1 (en) 2006-08-23 2007-08-20 Early Kick Detection in an Oil and Gas Well

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WO2008024806A2 true WO2008024806A2 (fr) 2008-02-28
WO2008024806A3 WO2008024806A3 (fr) 2008-04-24
WO2008024806A8 WO2008024806A8 (fr) 2008-08-07

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PCT/US2007/076463 WO2008024806A2 (fr) 2006-08-23 2007-08-22 Détection précoce de venue dans un puits de pétrole et de gaz
PCT/US2007/076464 WO2008024807A2 (fr) 2006-08-23 2007-08-22 Détection précoce d'un à-coup de pression dans un puits à pétrole ou à gaz

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PCT/US2007/076464 WO2008024807A2 (fr) 2006-08-23 2007-08-22 Détection précoce d'un à-coup de pression dans un puits à pétrole ou à gaz

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US (1) US20080047337A1 (fr)
GB (1) GB2454424B (fr)
NO (1) NO20090867L (fr)
WO (2) WO2008024806A2 (fr)

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NO20090867L (no) 2009-03-23
GB2454424A (en) 2009-05-06
GB2454424B (en) 2011-11-23
WO2008024806A8 (fr) 2008-08-07
US20080047337A1 (en) 2008-02-28
WO2008024807A2 (fr) 2008-02-28
WO2008024807A3 (fr) 2013-10-17
GB0903368D0 (en) 2009-04-08
WO2008024806A3 (fr) 2008-04-24

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