WO2005068994A1 - Procede et appareil permettant de determiner la contamination d'un filtrat de fond de puits a partir de mesures de densite - Google Patents

Procede et appareil permettant de determiner la contamination d'un filtrat de fond de puits a partir de mesures de densite

Info

Publication number
WO2005068994A1
WO2005068994A1 PCT/US2005/001497 US2005001497W WO2005068994A1 WO 2005068994 A1 WO2005068994 A1 WO 2005068994A1 US 2005001497 W US2005001497 W US 2005001497W WO 2005068994 A1 WO2005068994 A1 WO 2005068994A1
Authority
WO
WIPO (PCT)
Prior art keywords
fluid
density
filtrate
mixture
formation
Prior art date
Application number
PCT/US2005/001497
Other languages
English (en)
Inventor
Rocco Difoggio
Original Assignee
Baker Hughes Inc
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
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Publication of WO2005068994A1 publication Critical patent/WO2005068994A1/fr

Links

Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N29/00—Investigating 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
    • G01N29/02—Analysing fluids
    • G01N29/022—Fluid sensors based on microsensors, e.g. quartz crystal-microbalance [QCM], surface acoustic wave [SAW] devices, tuning forks, cantilevers, flexural plate wave [FPW] devices
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00—Indexing codes associated with group G01N29/00
    • G01N2291/01—Indexing codes associated with the measuring variable
    • G01N2291/014—Resonance or resonant frequency
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00—Indexing codes associated with group G01N29/00
    • G01N2291/10—Number of transducers
    • G01N2291/101—Number of transducers one transducer

Definitions

  • the present invention relates to the field of downhole formation fluid sample analysis in hydrocarbon producing wells. More particularly, the present invention 10 relates to a method and apparatus for determining the percentage of filtrate contamination in a formation fluid sample from a relationship between formation fluid density, filtrate density and sample density.
  • U.S. Patent number 6,182,499 discloses a system and method for characterization of materials and combinatorial libraries with mechanical oscillators.
  • U.S. patent number 5,734,098 discloses a method for monitoring and controlling chemical treatment of petroleum, petrochemical and processes with on-line quartz crystal microbalance sensors. The '098 method utilizes thickness shear mode (TSM) resonators, which simultaneously measure mass deposition and fluid properties such as viscosity and or density of a fluid.
  • TSM thickness shear mode
  • patent number 6,176,323 discloses drilling systems with sensors for determining properties of drilling fluid downhole.
  • the '323 patent discloses a plurality of pressure sensors at different depths to determine the fluid gradient.
  • U.S. patent number 5,741,962 discloses a method and apparatus for analyzing a formation fluid using acoustic measurements.
  • the '962 patent device acoustically determines density and compressibility from acoustic impedance and sound speed.
  • U.S. patent number 5,622,223 discloses a method and apparatus for formation fluid samples utilizing differential pressure measurements.
  • the '223 patent discloses an apparatus that provides two pressure gauges at different depths to determine density from a fluid pressure gradient.
  • U.S. patent number 5,006,845 uses differential fluid pressure at two depths to determine fluid density.
  • U.S. patent number 5,361,632 discloses a method and apparatus for determining multiphase hold up fractions using a gradiometer and a densiometer to provide a pressure gradient to determine fluid density.
  • U.S. patent number 5,204,529 discloses a method and apparatus for measuring borehole fluid density, formation density and or borehole diameter using back-scattered gamma radiation to determine fluid density.
  • the present invention provides a downhole system, apparatus and method to determine the percentage of oil-based or water-based mud filtrate contamination in a formation fluid sample.
  • the present invention determines the percentage of filtrate contamination in a sample comprised of a mixture of formation fluid (crude oil or brine) and filtrate.
  • the filtrate percentage is determined from a relationship between the densities of the contaminated formation fluid sample, the density of the formation fluid and the density of filtrate.
  • Filtrate is typically oleic (from oil-based mud) or aqueous (from water-based mud).
  • the density of formation fluid is determined from a series of high precision pressure measurements of formation fluid at a plurality of depths in a hydrocarbon producing well.
  • the present invention additionally provides a method and apparatus for determining sample cleanup from a leveling off in the reduction of the percentage of filtrate contamination in a fluid removed from a formation during continuous pumping.
  • the density of the oil based mud filtrate should be very close to the density of the original base oil at the same temperature and pressure, thus, the filtrate density is estimated using a density table at various pressures and temperatures. Alternatively, the filtrate density can be measured on site.
  • f the fraction of filtrate contamination in a mixture of the orginal formation fluid and a filtrate
  • f (pu — Po) I (P F - Po) and therefore the percentage of contamination is equal to 100 times f, which is the fraction of filtrate contamination in the mixture.
  • the filtrate is miscible with the original formation fluid.
  • this invention is applicable to a formation fluid comprised of crude oil contaminated by an oil-based mud filtrate.
  • this invention is applicable to a formation fluid comprised of brine contaminated by a water-based mud filtrate.
  • a downhole tool for determining the filtrate contamination percentage for a formation fluid sample comprising a tool deployed in a well bore formed in a formation. The tool communicates with a quantity of downhole fluid.
  • a pressure measuring device performs a series of pressure measurements of the downhole fluid at depth to determine the density of the original formation fluid.
  • a density measuring device such as a mechanical resonator is attached to the tool immersed in the recovered fluid sample.
  • a controller actuates the mechanical resonator and a monitor receives a response from the mechanical resonator in response to the actuation of the mechanical resonator in the fluid.
  • a processor is provided for determining a density of a fluid sample from the response of the mechanical resonator.
  • a tool is provided wherein the densities of the contaminated fluid sample, the original formation fluid and the filtrate are used to determine the percentage of the filtrate contamination for sample.
  • FIG. 1 is an illustration of a model for an equivalent circuit for a thickness- shear-mode (TSM) resonator complex impedance in a liquid environment
  • FIG 2 is an illustration of resonator connections in an embodiment
  • Figures 3A and 3B illustrate acquired data on the frequency response of a 32.768 kHz tuning fork resonator for a variety of common organic solvents generating a family of curves
  • Figure 4A and 4B illustrate values for ⁇ L and ⁇ Z plotted versus the solvent density and square root of the solvent viscosity density product, respectively
  • Figure 5 is a schematic diagram of an embodiment of the present invention deployed on a wireline in a downhole environment
  • Figure 6 is a schematic diagram of an embodiment of the present invention deployed on a drill string in a monitoring while drilling
  • the present invention provides a downhole method and apparatus to determine the percentage of mud filtrate contamination in a formation fluid sample.
  • the present invention determines the percentage of filtrate contamination in a sample comprised of a mixture of crude oil and oil based mud filtrate or of formation brine and water based mud filtrate.
  • the filtrate contamination percentage is determined from a relationship between the density of the filtrate-contaminated sample, the density of the pure formation fluid, and the density of the filtrate.
  • the density of formation fluid is determined from a series of high precision pressure measurements of formation fluid at a plurality of depths in a hydrocarbon producing well.
  • the present invention provides a function that performs a least squares fit of the pressure to depth.
  • the present invention additionally provides a method and apparatus for determining sample cleanup from a leveling off in the reduction of the percentage of filtrate contamination with continued pumping.
  • the present invention provides a downhole method and apparatus using a mechanical resonator, preferably, a tuning fork to provide real-time direct measurements and estimates of the density for formation fluid and filtrate in a hydrocarbon producing well.
  • the present invention additionally provides a method and apparatus for monitoring formation fluid or sample cleanup from a leveling off of the density over time as the fluid under investigation transitions from contaminated to substantially pure formation fluid.
  • Matsiev/Symyx references noted above describe the application of flexural mechanical resonators such as tuning forks, benders, etc. to liquid characterization for measuring density of a fluid. Additional complex electrical impedance produced by a liquid environment to such resonators is also described. Matsiev shows that this additional impedance can be represented by the sum of two terms: one that is proportional to liquid density and a second one that is proportional to the square root the of viscosity density product.
  • This Matsiev/Symyx impedance model is universally applicable to any resonator type that directly displaces liquid and has size much smaller than the acoustic wavelength in a liquid at its operation frequency.
  • Matsiev/Symyx model it is possible to separately extract liquid viscosity and density values from the flexural resonator frequency response, while conventional TSM resonators can measure only the viscosity density product.
  • Thickness-shear mode (TSM) quartz resonators have been applied to the determination of mechamcal properties of liquids for several decades. Oscillation of the TSM resonator surface exposed to liquid along a crystal-liquid interface produces a decaying viscous shear wave in liquid.
  • TSM resonator complex impedance in a liquid environment can be represented by equivalent circuit shown on Figure 1.
  • Equivalent parameters C s , 100 R 0 , 102 and Ln 106 represent respectively mechanical compliance, loss and inertia of the resonator in vacuum.
  • Additional impedance Z( ⁇ ) 108 produced by surrounding liquid is given by ( ⁇ p ⁇ ) (1 + i) per unit interface area, where ⁇ is the operation frequency, p is the liquid density, r ⁇ is the viscosity of the liquid.
  • Parallel capacitance C p an electrical capacitance measured between the resonator electrodes, is also affected by electrical properties of surrounding liquid.
  • Low-frequency piezoelectric resonators such as bar benders, disk benders, cantilevers, tuning forks, micro-machined membrane and torsion resonators are provided as flexural mechanical resonators. A wide variety of such resonators with operation frequency from hundreds of hertz up to a few MHz are commercially available.
  • An HP8751A network analyzer is one of many suitable generators that can be used to generate sweep frequencies and measure resonator response when the resonator was exposed to a variety of organic solvents.
  • the equivalent impedance of tuning forks is quite high, so the use of high impedance probe is desirable.
  • an exciter circuit 200 is provide and the resonator is connected as shown on Figure 2.
  • the resonator impedance and probe amplifier known input impedance form a frequency dependent voltage divider.
  • the frequency dependence of the normalized absolute value of the probe input voltage was recorded while resonator was submerged in various organic solvents.
  • the equivalent circuit from Figure 1 also describes the impedance of the flexural resonator with a modification for the additional impedance Z( ⁇ ).
  • Oscillation velocity at the interfaces of an oscillating flexural resonator does have a component normal to the interface, so some compression should occur.
  • the size of flexural resonators is much less than a wavelength of the compression wave in surrounding liquid at an operational frequency. Therefore low-frequency resonators are, in general, quite ineffective exciters of compression waves regardless of the oscillation mode.
  • the vorticity of the velocity field decays with the distance from the oscillating body in the same manner as the velocity decays with the distance from TSM resonator.
  • p is the liquid density
  • ⁇ is the liquid viscosity
  • a and B are the geometry factors that depend only on the resonator geometry and mode of oscillation.
  • FIGs. 3A and 3B acquired data 300, 302 on the frequency response of the 32.768 kHz tuning fork resonator for a variety of common organic solvents generating a family of curves, are shown in Figs. 3A and 3B.
  • the data shown in Figs. 3A, 3B, 4A and 4B was acquired by Symyx. Values for ⁇ Z, and ⁇ Z were determined by fitting the frequency response data to the proposed mathematical model. In general the model was found to be in excellent agreement with the data. The residuals could be entirely attributed to electronic noise rather than the difference between the model and the data.
  • the present invention provides a tuning fork or flexural resonator, which is excited, monitored and process to separately determine not only the density and viscosity of a fluid, but also the dielectric constant of a fluid.
  • the present exemplary resonator tuning forks are very small, approximately 2mm x 5mm. These tuning forks are inexpensive and have no macroscopically moving parts. Moreover, the resonator tuning forks can operate at elevated temperature and pressure. The tuning forks enable a more accurate method of determining viscosity and other fluid properties downhole than other known methods.
  • the tuning forks are provided by Symyx and are made of quartz with silver or gold electrodes.
  • Symyx states that the typical accuracy for determination is + 0.01% for density, + 1.0% for viscosity, and + .02% for dielectric constant.
  • the electrodes are connected to wires.
  • the connections between the wires and electrodes are covered with epoxy to prevent corrosion of the connections to the electrodes.
  • a common method for determining true formation fluid density is determination of the pressure gradient. Density is proportional to the slope of a plot of pressure versus depth over a depth interval of 50-150 feet. Generally, the tool is moved from point to point in the well so that the same pressure gauge is used to make all the pressure readings.
  • Density can also be measured using gamma rays as disclosed in U.S. patent number 5,204,529 (the '529 patent).
  • the measurement of fluid viscosity downhole can be estimated from the well- known inverse relationship between Nuclear Magnetic Resonance (NMR) decay time and viscosity.
  • NMR Nuclear Magnetic Resonance
  • any differential pressure gauge sensitive enough to determine density from a short-spacing (10-20 feet) pressure gradient should be sufficiently sensitive to determine viscosity from the pressure drop versus flow rate in a wireline formation tester.
  • the flexural mechanical oscillator generates a signal which is utilized to determine formation fluid properties and transmits the signal to a processor or intelligent completion system (ICE) 30 for receiving, storing and processing the signal or combination of signals.
  • ICE intelligent completion system
  • Figure 5 is a schematic diagram of an embodiment of the present invention deployed on a wireline in a downhole environment.
  • a downhole tool 10 containing a mechanical resonator 410, processor 411 and pressure measurement device 412 is deployed in a borehole 14.
  • the borehole is formed in formation 16.
  • Tool 10 is deployed via a wireline 12.
  • Data from the tool 10 is communicated to the surface to a computer processor 20 with memory inside of an intelligent completion system 30.
  • Figure 6 is a schematic diagram of an embodiment of the present invention deployed on a drill string 15 in a monitoring while drilling environment.
  • Figure 7 is a schematic diagram of an embodiment of the present invention deployed on a flexible tubing 13 in a downhole environment.
  • FIG 8 is a schematic diagram of an embodiment of the present invention as deployed in a wireline downhole environment showing a cross section of a wireline formation tester tool.
  • tool 416 is deployed in a borehole 420 filled with borehole fluid.
  • the tool 416 is positioned in the borehole by backup support arms 416.
  • a packer with a snorkel 418 contacts the borehole wall for extracting formation fluid from the formation 414.
  • Tool 416 contains tuning fork 410 disposed in flowline 426.
  • Any type of flexural mechanical oscillator that can make high precision density measurements when deployed downhole in the tool is suitable for use in the present invention. Examples of well known high precision density devices, are, but not limited to a Meller-Paar vibration U tube and a mechanical resonator.
  • the mechanical resonator shown in Figure 8 illustrated as a tuning fork is excited by an electric current applied to its electrodes and monitored to determine density, viscosity and dielectric coefficient of the formation fluid.
  • Numerous mechanical resonators are suitable for use for high density measurements for use with the present invention.
  • the electronics for exciting and monitoring the flexural mechanical resonator as shown in the Matsiev references are housed in the tool 10.
  • Pump 412 pumps formation fluid from formation 414 into flowline 426. Formation fluid travels through flow line 424 in into valve 420 which directs the formation fluid to line 422 to save the fluid in sample tanks or to line 418 where the formation fluid exits to the borehole.
  • FIG 9 A is a schematic diagram of an embodiment of the present invention illustrating a tuning fork 412 with tines 411 deployed in a fluid flow pipe 426.
  • Figure 9B is an alternative embodiment of the present invention in which the turning fork is recessed out of the flow pipe into a recess, cavity or clean out 428.
  • the present invention can be utilized in flowing fluid, as when a sample of well bore fluid or formation fluid is pumped through the tool and into the well bore.
  • the mechanical resonator which can be a bar bender, disk bender, cantilever, tuning fork, micro-machined membrane or torsion resonator, is immersed in the flowing fluid and used to determine the density, viscosity and dielectric constant for the fluid flowing in the tool.
  • baffles are provided in the flow path to protect the mechanical resonator from the physical stress of the flowing fluid.
  • a porous, sintered metal cap or a screen can also be used to cover the mechanical oscillator and protect it from pressure pulses and particles of sand or other solids. As shown in Figure 9B, in
  • the tuning fork is placed out of the flow path in a recess 428 to protect the tuning fork from harm from the turbulence and debris associated with the fluid sample flowing in the flow pipe.
  • the fluid sample flowing in the tool is stopped from flowing by stopping the pump 412 while the mechanical resonator is immersed in the fluid and used to determine the density, viscosity and dielectric constant for the static fluid trapped in the tool.
  • the operator, located at the surface and having access to over ride the processor/ICE 30 may make his own decisions and issue commands concerning well completion based on the measurements provided by the present invention.
  • the present invention may also provide data during production logging to determine the nature of fluid coming through a perforation in the well bore, for example, the filtrate and oil percentages.
  • FIG 10 an example of the present invention is shown as a process diagram for obtaining filtrate contamination percentage.
  • the present invention determines the density of crude oil, representative of native formation fluid substantially free of filtrate.
  • the present invention determines the density of filtrate.
  • the present invention determines the density of a sample taken from the formation. The sample comprises a percentage from 0 to 100 percent of formation fluid and 100 to 0 percent filtrate.
  • the present invention obtains a percentage of filtrate contamination for the sample taken from the formation.
  • block 1010 of Figure 10 is expanded to illustrate an example of determining the density of crude oil representative of formation fluid or determining the density of the formation fluid itself.
  • the present invention pumps a sample from the formation for a sufficient period of time in order to clean up filtrate from the sample being pumped from the formation, and start pumping mainly crude oil or native formation fluid, substantially absent of the filtrate contamination.
  • the present invention performs a series of high pressure measurements at a series of depths in the well bore or an oil column.
  • the present invention performs a least squares fit of pressure to depth.
  • the slope of the least square fit of pressure, P versus depth, H is equal to the density, p of crude oil or native formation fluid substantially free of filtrate content.
  • the density of the formation fluid can also be retrieved from processor 411 memory based on legacy or historical data for the formation or representative crude oil which is close to the density of the formation fluid for the formation under investigation.
  • the present invention determines the density using a flexural resonator immersed in formation fluid flowing after a sufficient period of time so that the formation fluid is essentially free of filtrate.
  • the density of the cleaned up flow is approximately equal to the density of the formation fluid substantially free of filtrate.
  • block 1020 is expanded to show an example of the determining the density of filtrate.
  • the present invention begins pumping or allowing fluid to flow into the sample line.
  • the present invention determines the density of initial flow with flexural resonator.
  • the initial flow is substantially made up of filtrate as the sample of fluid being pumped from the formation has not been cleaned up by pumping.
  • the density of the initial flow is approximately equal to the density of the filtrate.
  • Figure 13 an alternative example of determining filtrate density is shown.
  • the present invention begins pumping or allowing initial sample flow.
  • P pressure
  • h depth
  • the present invention processor looks up density of the original base oil or other fluid upon which the filtrate is based, in table at pressure and temperature to estimate filtrate density.
  • the table is stored in memory resident in the processor 411.
  • the method of the present invention is implemented as a set computer executable of instructions on a computer readable medium, comprising ROM, RAM, CD ROM, Flash or any other computer readable medium, now known or unknown that when executed cause a computer to implement the method of the present invention.

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  • Physics & Mathematics (AREA)
  • Acoustics & Sound (AREA)
  • Health & Medical Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Analytical Chemistry (AREA)
  • Biochemistry (AREA)
  • General Health & Medical Sciences (AREA)
  • General Physics & Mathematics (AREA)
  • Immunology (AREA)
  • Pathology (AREA)
  • Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)

Abstract

La présente invention concerne un procédé et un appareil de fond de puits permettant de déterminer le pourcentage de contamination d'un filtrat de boue à base d'eau ou de boue à base de pétrole dans un échantillon de fluide de formation. Cette invention détermine le pourcentage de contamination du filtrat dans un échantillon constitué d'un mélange de pétrole brut et d'un filtrat de boue à base de pétrole ou d'une saumure de formation et d'un filtrat de boue à base d'eau. Le pourcentage de contamination du filtrat est déterminé à partir de relations existant entre les densités d'un filtrat et d'un fluide de formation non contaminé. Le filtrat peut-être une boue à base de pétrole ou d'eau. La densité du fluide de formation est déterminée à partir d'une série de mesures de pression de haute précision du fluide de formation à une pluralité de profondeurs dans un puits de production d'hydrocarbure. La densité du filtrat est fournie par des mesures au fond du puits avec un résonateur mécanique de flexion ou par des mesures effectuées au fond du puits ou à la surface.
PCT/US2005/001497 2004-01-14 2005-01-14 Procede et appareil permettant de determiner la contamination d'un filtrat de fond de puits a partir de mesures de densite WO2005068994A1 (fr)

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WO2005068994A1 true WO2005068994A1 (fr) 2005-07-28

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN103266883A (zh) * 2013-05-13 2013-08-28 中国石油天然气股份有限公司 一种油井中利用相对密度找水的方法及装置
CN107831299A (zh) * 2017-09-29 2018-03-23 徐州蓝湖信息科技有限公司 一种石油样品检验检测分样装置
CN112834626A (zh) * 2019-11-22 2021-05-25 中国海洋石油集团有限公司 测定原油中油基泥浆污染程度的方法

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5622223A (en) * 1995-09-01 1997-04-22 Haliburton Company Apparatus and method for retrieving formation fluid samples utilizing differential pressure measurements
EP0953726A1 (fr) * 1998-04-01 1999-11-03 Halliburton Energy Services, Inc. Dispositif et procédé pour l'essai de fluides de formation dans un puit au moyen de signaux acoustiques
WO2002093126A2 (fr) * 2001-05-15 2002-11-21 Baker Hughes Incorporated Procede et appareil de caracterisation de fluides de fond impliquant la mise en oeuvre de resonateurs mecaniques de flexion
US20020184940A1 (en) * 2000-01-13 2002-12-12 Storm Bruce H. Single tube downhole densitometer

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5622223A (en) * 1995-09-01 1997-04-22 Haliburton Company Apparatus and method for retrieving formation fluid samples utilizing differential pressure measurements
EP0953726A1 (fr) * 1998-04-01 1999-11-03 Halliburton Energy Services, Inc. Dispositif et procédé pour l'essai de fluides de formation dans un puit au moyen de signaux acoustiques
US20020184940A1 (en) * 2000-01-13 2002-12-12 Storm Bruce H. Single tube downhole densitometer
WO2002093126A2 (fr) * 2001-05-15 2002-11-21 Baker Hughes Incorporated Procede et appareil de caracterisation de fluides de fond impliquant la mise en oeuvre de resonateurs mecaniques de flexion

Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN103266883A (zh) * 2013-05-13 2013-08-28 中国石油天然气股份有限公司 一种油井中利用相对密度找水的方法及装置
CN107831299A (zh) * 2017-09-29 2018-03-23 徐州蓝湖信息科技有限公司 一种石油样品检验检测分样装置
CN107831299B (zh) * 2017-09-29 2021-03-09 徐州蓝湖信息科技有限公司 一种石油样品检验检测分样装置
CN112834626A (zh) * 2019-11-22 2021-05-25 中国海洋石油集团有限公司 测定原油中油基泥浆污染程度的方法
CN112834626B (zh) * 2019-11-22 2022-08-02 中国海洋石油集团有限公司 测定原油中油基泥浆污染程度的方法

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