WO2013033682A1 - Système et procédé d'élimination de bruit à partir de de données de mesure - Google Patents

Système et procédé d'élimination de bruit à partir de de données de mesure Download PDF

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Publication number
WO2013033682A1
WO2013033682A1 PCT/US2012/053587 US2012053587W WO2013033682A1 WO 2013033682 A1 WO2013033682 A1 WO 2013033682A1 US 2012053587 W US2012053587 W US 2012053587W WO 2013033682 A1 WO2013033682 A1 WO 2013033682A1
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WO
WIPO (PCT)
Prior art keywords
pressure
derivative
time window
pressure measurement
pressure measurements
Prior art date
Application number
PCT/US2012/053587
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English (en)
Inventor
Peter S. Hegeman
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
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 Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited filed Critical Schlumberger Canada Limited
Priority to US14/241,860 priority Critical patent/US20140230538A1/en
Publication of WO2013033682A1 publication Critical patent/WO2013033682A1/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
    • E21B47/06—Measuring temperature or pressure
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/48—Processing data
    • 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor

Definitions

  • a drilling tool is driven into the ground surface to create a wellbore through which the hydrocarbons are extracted.
  • a typical system for drilling an oil or gas wellbore has a tubular drill pipe, known as a "drill string," and a drill bit located at the lower end of the drill string.
  • the drill string is suspended within the wellbore and may be formed by drill pipes joined together, a coiled tubing string, casing joined together, and/or combinations thereof.
  • mud drilling fluid
  • a surface pumping system typically generates circulation of the mud by delivering the mud to the central passageway of the drill string and receiving mud from the annulus of the wellbore. More specifically, the circulating mud typically travels downhole through the central passageway of the drill string, exits the drill string at nozzles that are located near the drill bit and returns to the surface pumping system through the annulus of the wellbore.
  • One technique to rotate the drill bit involves applying a rotational force to the drill string at the surface of the wellbore to rotate the drill bit at the bottom of the drill string.
  • Another technique to rotate the drill bit uses the mud flowing through the drill string to drive a downhole mud motor located near the drill bit. The mud motor responds to the mud flow to produce a rotational force that turns the drill bit.
  • the drilling of the wellbore may relate to operations to install segments of a casing string which lines and supports the wellbore. More specifically, the drilling and casing installation operations may involve the following repetitive sequence: a particular segment of the wellbore is drilled; then, a casing section is inserted and cemented into the newly drilled segment of the wellbore; and then the drilling of the next segment of the IS1 1 .0682-WO-PCT wellbore begins.
  • downhole pressure may be interpreted to analyze the hydrocarbon presence in the formation. Therefore, measuring and monitoring of the downhole pressure is instrumental to the drilling process for hydrocarbons.
  • the pressure derivative is the starting point for reservoir flow- regime identification.
  • the pressure derivative is also invaluable for diagnosing hardware problems, wellbore-induced anomalies, and pressure gauge problems.
  • the pressure derivative provides the basis for modern well test interpretation methodology and has become a common feature in well test interpretation software.
  • the derivative of the measured data is not capable of being interpreted or, worse, misinterpreted by the analyst because of various artifacts of the measuring and differentiating process collectively termed "noise".
  • noise a wide variety of smoothing methods have been proposed. For example, Bourdet et al, (See e.g.
  • the current practice is to use centuries-old techniques for interpolating data tables (backward, forward, or central difference typically utilizing three points). When viewed in the frequency domain, these techniques exaggerate high frequency noise and distort the "true" dpldt curve.
  • the data are then typically smoothed by choosing the points used in the calculation a sufficient distance from the point of interest. This distance, defined as L, is expressed in terms of the appropriate time function.
  • L is expressed in terms of the appropriate time function.
  • the idea of smoothing the derivative is considered somewhat unreliable due to the subjective choosing of L. If the value assigned to L is too large, the character of the actual signal will be distorted. Nevertheless, judging by the standard use of this method in commercial well testing software, it has become the most widely used.
  • FIG. 1A illustrates a schematic diagram, including a cross-sectional view, of a formation testing tool with a probe in a vertical wellbore in accordance with embodiments of the present invention and which can be used in practicing embodiments of the method of the present invention.
  • FIG. IB illustrates a schematic diagram, including a cross-sectional view, of a formation testing packer in a vertical wellbore in accordance with embodiments of the present invention and which can be used in practicing embodiments of the method of the present invention.
  • FIG. 1C illustrates a block diagram of electronic components of a formation testing tool that may be used in accordance with embodiments of the present invention and which can be used in practicing embodiments of the method of the present invention.
  • IS1 1 .0682-WO-PCT illustrates a block diagram of electronic components of a formation testing tool that may be used in accordance with embodiments of the present invention and which can be used in practicing embodiments of the method of the present invention.
  • FIG. 2 illustrates a differentiation method using three consecutive data points.
  • FIG. 3 illustrates a differentiation method using a smoothing interval L.
  • FIG. 4 illustrates a differentiation method using smoothing intervals and Z 2 .
  • FIG. 5 illustrates a plurality of pressure measurements.
  • FIG. 6 illustrates a plurality of pressure measurements during a final pressure buildup.
  • FIG. 7 illustrates a plurality of pressure measurements over a five-minute duration.
  • FIG. 8 A illustrates a buildup pressure derivative using the Bourdet method
  • FIG. 11 illustrates pressure versus time during a final buildup with two outlier points added.
  • the present disclosure generally relates to a system and a method for removing noise from measurement data. More specifically, the present disclosure relates to a system and a method for accurately measuring downhole pressure in a wellbore by reducing the effects of artifacts or 'noise' in the pressure-derivative curve. Moreover, the system and the method may use the least-squares and least-absolute-deviations methods to calculate a pressure-derivative curve of pressure data gathered from a downhole tool.
  • FIG. 1A and FIG. IB schematically illustrate a wellbore system 10, which may be an on-shore wellbore or an off-shore wellbore system, in which the present systems and methods for analyzing dynamic data and/or estimating and/or determining pressure of a subsurface geological reservoir 14 (hereinafter “reservoir 14") may be implemented.
  • reservoir 14 a subsurface geological reservoir 14
  • a downhole tool 16 (hereinafter “tool 16") may be lowered and/or run into the wellbore 12 and/or may extend downward into the wellbore 12. As a result, the tool 16 may be positioned within the wellbore 12 and/or may be located adjacent to one or more walls 18 (hereinafter "walls 18") of the wellbore 12.
  • the tool 16 may be a formation testing tool and/or may be configured to collect one or more measurements and/or data relating to one or more characteristics and/or properties associated with the wellbore 12, the walls 18 of the wellbore 12 and/or the reservoir 14.
  • the tool 16 may be deployed via a wireline, slickline, a cable, coiled tubing, drill pipe or other types of conveyance as will be appreciated by ordinary skill in the art.
  • the measurements and/or data relating to characteristics and/or properties associated with the wellbore 12, the walls 18 of the wellbore 12 and/or the reservoir 14 may be used diagnostically to provide critical information about the reservoir 14.
  • a pressure gauge can be used to sense the pressure in the reservoir 14. That is, the pressure gauge can be used to sense the 'reaction' of the reservoir to a change in the flow rate. By measuring that 'reaction', one can determine a significant amount of information about the reservoir, such as the size of the reservoir, how much fluid is in the IS1 1 .0682-WO-PCT reservoir, the permeability of the reservoir, boundaries, and other important properties of
  • the tool 16 may be a wireline configurable tool which is a tool commonly conveyed in the wellbore 12 by wireline cable 15, such as, for example, a wireline cable 15 as known to one having ordinary skill in the art.
  • the wireline configurable tool may be a tool for formation testing, or a logging tool or testing
  • tool for sampling or measuring properties and/or characteristics associated with the wellbore 12, the walls 18 of the wellbore 12 and/or the reservoir 14. It should be understood that the tool 16 may be any wireline configurable tool as known to one of ordinary skill in the art.
  • the tool 16 may be a tool configured to fluidly communicate
  • a probe 20 as shown in FIG. 1A a single-packer formation testing tool 26 as shown in FIG. IB, a dual-probe formation testing tool or multi-probe formation testing tool or a dual-packer formation testing tool (not shown in the drawings), and/or any combination thereof.
  • FIG. 1A shows a tool 16 having a probe 20 that may be extended outwardly from
  • the probe 20 can provide fluid communication between the reservoir 14 and/or the wellbore 12 and the tool 16. As a result, the probe 20 may abut or contact the walls 18 of the wellbore 12 and/or may penetrate and/or extend into the walls 18 of the wellbore 12. It should be understood that the tool 16 may include any number of probes as known to one of
  • FIG. IB shows the tool 16 having a single-packer tool 26 configured to fluidly communicate with the reservoir 14 in embodiments of the disclosure.
  • the single-packer tool 26 may expand or inflate from a first position having a first diameter to a second position having a second diameter greater than the first diameter. If inflated, the single-packer tool 26
  • the 170 packer tool 26 may seal against the walls 18 of the wellbore 12 to isolate a first portion of the wellbore 12 from a second portion of the wellbore 12.
  • the tool 16 may IS1 1 .0682-WO-PCT conduct, execute and/or complete one or more downhole tests, such as, for example, a local production test, a buildup test, and and/or an interference test.
  • the interference test 175 may include an interval pressure transient test (hereinafter "IPTT test") and/or a vertical interference test.
  • a port 24 on the packer element 26 may obtain formation fluid from the reservoir.
  • the tool 16 may measure data associated with, for example, transient flow regimes of the reservoir 14.
  • the tool 16 may be configured and/or adapted to collect and/or measure
  • the tool 16 may have one or more sensors to measure pressure data.
  • the tool 16 may be, for example, a formation testing tool incorporated into a tool string which may have been deployed or run into the wellbore 12 during a formation test,
  • the tool 16 may be configured and/or adapted to collect, test and/or evaluate one or more formation characteristics and/or properties associated with the reservoir 14, such as formation pressure data and/or permeability distributions data for the reservoir 14.
  • the tool 16 may measure and/or may collect dynamic data, such as, for example,
  • pressure data which may represent one or more local pressure measurements at one or more locations within the wellbore 12 which may be traversing the reservoir 14.
  • One or more characteristics and/or properties associated with the wellbore 12, the walls 18 of the wellbore 12 and/or the reservoir 14 may be evaluated, measured, determined and/or calculated based at least in part on the collected dynamic data and/or in part on the input
  • the tool 16 may detect, measure and/or collect one or more measurements and/or data relating to one or more characteristics and/or properties associated with the wellbore 12, the walls 18 of the wellbore 12 and/or the reservoir 14.
  • the measurements obtained may be, but are not limited to, pressure, flow rate, density, viscosity and velocity.
  • the tool 16 may communicate with the surface equipment, such as, for IS1 1 .0682-WO-PCT example, a surface system processor 104 (hereinafter "processor 104") located at the Earth's surface 11 via wellbore telemetry.
  • the wellbore telemetry may have, for example, wireline telemetry, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, wire-drill pipe telemetry and/or real-time bidirectional drill string telemetry and
  • the processor 104 may be located locally or remotely with respect to the wellbore system 10.
  • the processor 104 may be located in a remote location with respect to the wellbore system 10, such as, for example, a testing lab, a research and development facility and/or the like. It should be understood that the type of wellbore telemetry utilized by the telemetry device may be any type of telemetry capable of
  • Software and/or one or more computer programs may be stored in a memory 102 connected to and/or in electronic communication with the tool 16.
  • the software and/or one or more computer programs may be executed by the tool 16 to compress and/or
  • the software may compress data and/or information collected by the tool 16 before transmitting the compressed data uphole to the processor 104 at the Earth's surface 11.
  • the memory 102 may also be located at the Earth's surface 11. The measurements and/or data may be sent uphole to the Earth's surface 11 to be processed and/or analyzed.
  • the data may be processed and/or analyzed by the processor 104 and/or with the software to reconstruct, process, analyze, estimate and/or determine the measurements and/or data collected.
  • the processed, analyzed, reconstructed, estimated and/or determined measurements and/or data collected and/or tested by the probe 20 or single- packer 26 of the tool 16 may be accessible and/or viewable by an operator at the Earth's
  • a display 106 which may be connected to and/or in data communication with the processor 104 and/or the memory 102.
  • the tool 16 may be configured and/or may be adapted to conduct and/or to execute a drawdown test and/or a buildup test.
  • a drawdown test a seal is made IS1 1 .0682-WO-PCT
  • Fluid from the reservoir 14 is then drawn into the tool 16 by, for example, decreasing pressure in the tool 16. During the drawing of the fluid, pressure measurements can be obtained. The drawdown is completed when the fluid pumping into the tool from the reservoir 14 is ceased. A buildup portion of the test may
  • fluid from the formation continues to enter the tool 16 at an ever-decreasing rate of flow until, given a sufficient time, the pressure in the flowline is the same as the pressure in the reservoir 14.
  • the tool 16 may measure, analyze, collect and/or determine pressure measurements using data collected by the probe 20 or single-packer 26 in the wellbore 12. As the pressure builds, one or
  • the pressure measurements obtained during the drawdown and buildup test can be obtained at predetermined time increments, such as every one-tenth of a second. In an embodiment, a multitude of the pressure measurements can be obtained.
  • the data collected by the tool 16 and/or other tools may be analyzed. One example is described herein as formation pressure measurements. This
  • Bourdet et al. have proposed that the pressure derivative may be computed using a 3 -point central difference formula given by:
  • Bourdet et al proposes to reduce the noise effects by choosing the calculation 275 points i-k and i+j to be sufficiently distant from point i, such that the pressure change between the points is meaningful.
  • Bourdet et al. note that, if the points are chosen to be too distant from point i, the shape of the derivative curve is distorted.
  • FIG. 4 shows this effect. Although the differentiation interval is nearly doubled from L ⁇ to L 2 , no reduction in noise results.
  • Another scheme to reduce the noise is to decimate the data before performing the computation; again, the result may be a distorted derivative curve that may lack essential features because of excessive decimation.
  • the differentiation interval L may be established according to a time window. That is, when calculating pressure derivative, a time window of a given size may be defined about each pressure measurement. Thus, the time
  • window may be defined about point i such that a plurality of measurements taken during the time window are used to compute the pressure derivative at point i.
  • the size of the time window may be based on a function, such as, for example, a logarithmic function of time.
  • the size of the time window may alternatively be equal throughout the test.
  • the pressure measurements are taken with respect to time.
  • a least-squares formula can be
  • FIG. 5 presents the pressure data 500 from a strain gauge during a ten-hour test of a low-mobility zone.
  • the test has a pretest 510, extended pumpout period 520, and final buildup 530.
  • FIG. 6 illustrates the pressure data 500 during the 1000-second final buildup 530 of the ten-hour test shown in FIG. 5.
  • FIG. 7 displays the pressure data 500
  • FIG. 7 exhibits the typical resolution-banded pattern characteristic of the strain gauge, although the pressure is still building at about 0.1 psi/minute at the end of the period.
  • the modified method produces a more uniform curve 900B, thus allowing for flow-regime identification.
  • the flow regime may be radial flow and/or spherical flow.
  • FIGS. 9B and 10A indicate that the least-squares method produces a derivative of similar quality as the standard Bourdet method, yet the least- squares uses a five-times smaller differentiation interval.
  • a smaller differentiation interval is advantageous because a smaller differentiation interval reduces the likelihood
  • the method of least squares may be sensitive to outlying points in a data set.
  • the sensitivity to outlying points is demonstrated by creating two outlier points 1101, 1102 in the buildup curve 1100 of FIG. 11.
  • the pressure data are presented showing these outlier points.
  • the first outlying point has been created by adding 10 psi to the measured
  • the method uses only three points regardless of the size of L so the existence of outlying data points 1101 and 1102 affects very few
  • the derivative curve 1200B from the least-squares method displayed in FIG. 12B shows that any outlying data points 1101 and 1102 affect a considerable range of derivative values 1210B.
  • the flow regime 1220B may be difficult to identify.
  • the method of least absolute deviations is a technique similar to least 365 squares; however, the LAD method attempts to minimize the sum of absolute errors as opposed to the sum of square errors which is the basis for least squares.
  • the LAD method is robust in that the LAD method is resistant to outliers.
  • the LAD method is also known IS1 1 .0682-WO-PCT in the art as the least absolute errors or least absolute value method.
  • FIG. 12C displays the pressure derivative 1200C for the buildup computed using
  • the LAD derivative curve 1200C is comparable in quality to that of FIG. 10B, having been computed using the least-squares method with no-outlier data.
  • the improved quality of the derivative curve 1200C allows the flow regime 1220C to be identified.
  • LAD regression does not have an analytical solution. Therefore, an iterative solution is required.
  • the method of iteratively- reweighted least squares (IRLS) may be used (McCullagh, P. an Nelder, J. A; 1989; Generalized Linear Models, Second Edition; Chapman and Hall).
  • IRLS is generally used to minimize the least absolute error (as opposed to the
  • IRLS may be used to solve a least absolute-deviations problem.
  • the method may, for example, converge in three to five iterations.
  • a person of ordinary skill in the art will appreciate that more or less iterations may be used.
  • the modification retains the simplicity of the Bourdet et al. method because a single adjustable parameter is still used.
  • Application of the disclosed method achieves a significantly smoother derivative curve than the standard Bourdet et al. method.
  • the proposed method may be implemented with a least-squares computation or a least- absolute-deviations computation.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Fluid Mechanics (AREA)
  • General Physics & Mathematics (AREA)
  • Remote Sensing (AREA)
  • Acoustics & Sound (AREA)
  • Chemical & Material Sciences (AREA)
  • Analytical Chemistry (AREA)
  • Measuring Fluid Pressure (AREA)

Abstract

L'invention porte sur un système et/ou des procédés d'élimination de bruit à partir de de données de mesure. Par exemple, des mesures de pression peuvent être utilisée pour identifier un régime de flux à l'aide de la dérivée de chacune des mesures de pression. Une fenêtre temporelle peut être définie autour de chaque mesure de pression et de nombreuses ou même toutes les mesures de pression dans la fenêtre temporelle peuvent être utilisées pour calculer la dérivée de pression de chaque mesure de pression. Une méthode des moindres carrés ou une méthode des moindres déviations absolues peut être utilisée pour calculer une courbe de la dérivée de pression. La méthode des moindres carrés re-pondérés de manière itérative peut être utilisée pour résoudre les problèmes des moindres déviations absolues pour calculer une courbe de dérivée de pression ayant un lissage amélioré.
PCT/US2012/053587 2011-09-02 2012-09-03 Système et procédé d'élimination de bruit à partir de de données de mesure WO2013033682A1 (fr)

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US14/241,860 US20140230538A1 (en) 2011-09-02 2012-09-03 System And Method for Removing Noise From Measurement Data

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US201161530720P 2011-09-02 2011-09-02
US61/530,720 2011-09-02
US201161532993P 2011-09-09 2011-09-09
US61/532,993 2011-09-09

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Families Citing this family (4)

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Publication number Priority date Publication date Assignee Title
CA2899144A1 (fr) * 2013-01-31 2014-08-07 Schlumberger Canada Limited Procede pour l'analyse de donnees de test preliminaire de testeur de formation
US20170220050A1 (en) * 2014-10-22 2017-08-03 Landmark Graphics Corporation Flow regime identification apparatus, methods, and systems
US9933535B2 (en) 2015-03-11 2018-04-03 Schlumberger Technology Corporation Determining a fracture type using stress analysis
US20230349286A1 (en) * 2020-09-11 2023-11-02 Schlumberger Technology Corporation Geologic formation characterization

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US20040133350A1 (en) * 2003-01-08 2004-07-08 Schlumberger Technology Corporation Digital pressure derivative method and program storage device
WO2009020719A1 (fr) * 2007-08-09 2009-02-12 Schlumberger Canada Limited Elimination du bruit de vibration de mesures de flûtes multicomposants
US20100171639A1 (en) * 2006-05-10 2010-07-08 Brian Clark Wellbore telemetry and noise cancellation systems and methods for the same

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US5184508A (en) * 1990-06-15 1993-02-09 Louisiana State University And Agricultural And Mechanical College Method for determining formation pressure
US5602334A (en) * 1994-06-17 1997-02-11 Halliburton Company Wireline formation testing for low permeability formations utilizing pressure transients
US5644076A (en) * 1996-03-14 1997-07-01 Halliburton Energy Services, Inc. Wireline formation tester supercharge correction method

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Publication number Priority date Publication date Assignee Title
US20040133350A1 (en) * 2003-01-08 2004-07-08 Schlumberger Technology Corporation Digital pressure derivative method and program storage device
US20100171639A1 (en) * 2006-05-10 2010-07-08 Brian Clark Wellbore telemetry and noise cancellation systems and methods for the same
WO2009020719A1 (fr) * 2007-08-09 2009-02-12 Schlumberger Canada Limited Elimination du bruit de vibration de mesures de flûtes multicomposants

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