US20120063267A1 - Well Monitoring by Means of Distributed Sensing Means - Google Patents

Well Monitoring by Means of Distributed Sensing Means Download PDF

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Publication number
US20120063267A1
US20120063267A1 US13/320,877 US201013320877A US2012063267A1 US 20120063267 A1 US20120063267 A1 US 20120063267A1 US 201013320877 A US201013320877 A US 201013320877A US 2012063267 A1 US2012063267 A1 US 2012063267A1
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Prior art keywords
fibre
data
well
acoustic
fracture
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English (en)
Inventor
David John Hill
Magnus McEwen-King
Patrick Tindel
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Optasense Holdings Ltd
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Qinetiq Ltd
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Priority claimed from GB0909038A external-priority patent/GB0909038D0/en
Priority claimed from GB0919915A external-priority patent/GB0919915D0/en
Application filed by Qinetiq Ltd filed Critical Qinetiq Ltd
Publication of US20120063267A1 publication Critical patent/US20120063267A1/en
Assigned to QINETIQ LIMITED reassignment QINETIQ LIMITED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: HILL, DAVID JOHN, MCEWEN-KING, MAGNUS, TINDELL, PATRICK PHILLIP
Assigned to OPTASENSE HOLDINGS LTD. reassignment OPTASENSE HOLDINGS LTD. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: QINETIQ LIMITED
Abandoned legal-status Critical Current

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    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • E21B47/16—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/11—Perforators; Permeators
    • E21B43/116—Gun or shaped-charge perforators
    • E21B43/1185—Ignition systems
    • E21B43/11857—Ignition systems firing indication systems
    • 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
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
    • E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
    • 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
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
    • 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
    • G01N29/036—Analysing fluids by measuring frequency or resonance of acoustic waves
    • 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
    • G01V1/50—Analysing data
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V8/00—Prospecting or detecting by optical means
    • G01V8/02—Prospecting
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V8/00—Prospecting or detecting by optical means
    • G01V8/10—Detecting, e.g. by using light barriers
    • G01V8/12—Detecting, e.g. by using light barriers using one transmitter and one receiver
    • G01V8/16—Detecting, e.g. by using light barriers using one transmitter and one receiver using optical fibres
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01H—MEASUREMENT OF MECHANICAL VIBRATIONS OR ULTRASONIC, SONIC OR INFRASONIC WAVES
    • G01H9/00—Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means
    • G01H9/004—Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means using fibre optic sensors
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/14—Signal detection
    • G01V2210/142—Receiver location
    • G01V2210/1429—Subsurface, e.g. in borehole or below weathering layer or mud line
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/60—Analysis
    • G01V2210/64—Geostructures, e.g. in 3D data cubes
    • G01V2210/646—Fractures

Definitions

  • the present invention relates to monitoring of production wells such as oil and gas wells. Such monitoring is often referred to as downhole monitoring.
  • the present invention relates to downhole monitoring using distributed acoustic sensing (DAS).
  • DAS distributed acoustic sensing
  • Fibre optic sensors are becoming a well-established technology for a range of applications, for example geophysical applications. Fibre optic sensors can take a variety of forms, and a commonly adopted form is to arrange a coil of fibre around a mandrel. Point sensors such as geophones or hydrophones can be made in this way, to detect acoustic and seismic data at a point, and large arrays of such point sensors can be multiplexed together using fibre optic connecting cables, to form an all fibre optic system. Passive multiplexing can be achieved entirely optically, and an advantage is that no electrical connections are required, which has great benefit in harsh environments where electrical equipment is easily damaged.
  • Fibre optic sensors have found application in downhole monitoring, and it is known to provide an array of geophones in or around a well to detect seismic signals with the aim of better understanding the local geological conditions and extraction process.
  • a problem with such an approach is that geophones tend to be relatively large and so installation downhole is difficult. In addition geophones tend to have limited dynamic range.
  • WO 2005/033465 describes a system of downhole acoustic monitoring using a fibre having a number of periodic refractive index perturbations, for example Bragg gratings. Acoustic data is retrieved by portions of the fibre and used to monitor downhole conditions.
  • a method for downhole monitoring comprising interrogating an unmodified optic fibre arranged along the path of a well bore to provide distributed acoustic sensing; simultaneously sampling data gathered from a plurality of contiguous portions of said fibre; and processing said data to determine one or more well bore parameters.
  • DAS Distributed acoustic sensing
  • Optical pulses are launched into the fibre and the radiation backscattered from within the fibre is detected and analysed. Rayleigh backscattering is most usually detected.
  • the fibre can effectively be divided into a plurality of discrete sensing portions which may be (but do not have to be) contiguous.
  • distributed acoustic sensor will be taken to mean a sensor comprising an optic fibre which is interrogated optically to provide a plurality of discrete acoustic sensing portions distributed longitudinally along the fibre and acoustic shall be taken to mean any type of mechanical vibration or pressure wave, including seismic waves.
  • the method may therefore comprise launching a series of optical pulses into said fibre and detecting radiation Rayleigh backscattered by the fibre; and processing the detected Rayleigh backscattered radiation to provide a plurality of discrete longitudinal sensing portions of the fibre.
  • optical is not restricted to the visible spectrum and optical radiation includes infrared radiation and ultraviolet radiation.
  • the single length of fibre is typically single mode fibre, and is preferably free of any mirrors, reflectors, gratings, or (absent any external stimulus) change of optical properties along its length.
  • This provides the advantage that an unmodified, substantially continuous length of standard fibre can be used, requiring little or no modification or preparation for use.
  • a suitable DAS system is described in GB2442745 for example, the content of which is hereby incorporated by reference.
  • Such a sensor may be seen as a fully distributed or intrinsic sensor as it uses the intrinsic scattering processed inherent in an optical fibre and thus distributes the sensing function throughout the whole of the optical fibre.
  • the length and arrangement of fibre sections corresponding to each channel is determined by the interrogation of the fibre. These can be selected according to the physical arrangement of the fibre and the well it is monitoring, and also according to the type of monitoring required. In this way, the distance along the fibre, or depth in the case of a substantially vertical well, and the length of each fibre section, or channel resolution, can easily be varied with adjustments to the interrogator changing the input pulse width and input pulse duty cycle, without any changes to the fibre.
  • Distributed acoustic sensing can operate with a longitudinal fibre of 40 km or more in length, for example resolving sensed data into 10 m lengths. In a typical downhole application a fibre length of a few kilometres is usual, i.e.
  • a fibre runs along the length of the entire borehole and the channel resolution of the longitudinal sensing portions of fibre may be of the order or 1 m or a few metres.
  • the spatial resolution i.e. the length of the individual sensing portions of fibre, and the distribution of the channels may be varied during use, for example in response to the detected signals.
  • the optic fibre is preferably located within the well bore to be monitored.
  • the optic fibre runs along the exterior of the well casing, although the fibre could, in some embodiments, be arranged to run within the casing.
  • the optic fibre may be attached to the well casing as it is inserted into the well bore and, if on the exterior of the casing, subsequently cemented in place in those sections of the well which are cemented.
  • the fibre may therefore follow the general route of the well bore and extends at least as far into the well bore as the region it is wished to monitor, preferably for substantially the whole length of the well bore.
  • the fibre can therefore be interrogated to provide one, or preferably a plurality, of acoustic sensing portions arranged along the whole or part or parts of the well bore.
  • the positions or locations of the sensing portions of interest should generally be known from a knowledge of the length along the fibre, and hence the well.
  • the method may comprise monitoring the acoustic disturbances in the fibre generated by the process, e.g. perforation, to determine portions of the fibre that sections of interest of the well. For instance, portions of the fibre which exhibit the greatest acoustic disturbance intensity during perforation will generally correspond to the location where the perforation charges fired.
  • the method of the present invention may be used to determine at least one well bore parameter.
  • the at least one well bore parameter may comprise a well condition profile.
  • the well condition profile may be an acoustic profile of one or more sections of well or the whole of the length of the well.
  • the acoustic profile may be obtained by measuring the acoustic signals determined by the DAS sensor in response to an acoustic stimulus.
  • the acoustic stimulus could be stimulus which is applied specifically for the purposes of determining an acoustic profile.
  • the perforation step of well production involves firing one or more perforation charges. This provides an intense acoustic stimulus that can be used to acquire an acoustic profile of the well at that stage of completion.
  • Well bore parameters may be provided in real-time.
  • Real-time means that there is no significant delay between an acoustic signal being detected by the fibre and the well bore parameter being generated.
  • the method may involve providing a generally accurate representation of the acoustic signals being currently detected by the distributed acoustic sensor.
  • the acoustic signals from one or more relevant section of fibre may be played on a suitable audio device. This will provide the personnel operating the well, or a particular downhole process, with audible feedback of what is actually happening down the well. An operator listening to the signals produced by an acoustic channel of the fibre may therefore be provided with real-time audio feedback of the acoustic disturbance downhole.
  • the method of the present invention uses a fibre optic which may to be located on the exterior of the well casing to provide a downhole sensor in the well bore during formation of the well and also during subsequent oil/gas production.
  • the method may comprise analysing the intensity levels of acoustic disturbances detected downhole.
  • the acoustic information from various sensing portions of the fibre may be displayed on a suitable display.
  • the intensity of the selected channels may be displayed.
  • the display may show, for each channel, the current intensity, maximum intensity and/or an average intensity of the acoustic signals over a predefined or selected time period in a histogram type arrangement.
  • the real-time indication may comprise a waterfall plot representing intensity by colour or greyscale and plotting the intensity for each channel against time.
  • the method may also provide performing frequency analysis on the data and the real-time indication may comprise an indication of the frequency of acoustic signals detected by at least one longitudinal portion of fibre in the vicinity of the downhole process.
  • the indication of frequency may comprise a histogram type plot of current, maximum or average frequency against channel and/or a waterfall type plot with frequency represented by colour or greyscale such as described above.
  • the indication may additionally or alternatively comprise an indication of the intensity within a particular frequency band.
  • the data may be filtered so as to include only acoustic disturbances with a frequency within the frequency range of the particular band. Analysing the data by spectral band can more clearly indicate the acoustic difference between various channels in some situations.
  • an operator may be able to determine if there is any significant activity in any particular channel.
  • Providing an audible indication of the data from the DAS sensor and/or providing an indication of the intensity and/or frequency of the data provides useful feedback data that can be generated quickly without an excessive processing overhead.
  • the method may also comprise detecting transients, especially relatively high frequency transients, in the acoustic signal.
  • the method may also comprise using data from at least one other sensor at another location.
  • the at least one additional sensor may comprise another fibre optic distributed acoustic sensor, for instance a DAS sensor which is placed in an existing well in the surrounding area and/or a DAS sensor in an observation bore hole drilled nearby and/or a DAS sensor arranged at or near the surface of the general area, such as buried in a trench.
  • the combination of data from many different sensors in different locations may allow the point of origin, or at least general area of origin, of acoustic disturbances to be determined.
  • a fibre optic interrogator adapted to provide distributed acoustic sensing on an unmodified fibre arranged along the path of a well bore; a sampler arranged to sample a plurality of channels output from said interrogator simultaneously to provide acoustic data from a plurality of contiguous portions of said fibre at each of a plurality of times; and a data analyser adapted to process said sampled data to detect well events and output parameters associated with detected events.
  • the invention also provides a processor, computer program and/or a computer program product for carrying out any of the methods described herein and/or for embodying any of the apparatus features described herein, and a computer readable medium having stored thereon a program for carrying out any of the methods described herein and/or for embodying any of the apparatus features described herein.
  • FIG. 1 shows apparatus for monitoring a well using DAS
  • FIG. 2 illustrates the output of the system of FIG. 1 ;
  • FIG. 3 is a schematic representation of a perforation event as monitored by an embodiment of the present invention.
  • FIG. 4 illustrates seismic detection and parameterisation steps for fracture monitoring
  • FIG. 5 shows the results of inflow monitoring having been enhanced using variance statistics.
  • a fibre optic cable 102 is included along the path of a well, which in the present example is a gas well, and may be on or offshore.
  • the well is formed at least in part by a metallic production casing 104 inserted into a bore hole 106 , with the space between the outer wall of the casing and the hole being back filled with cement 108 in the present example.
  • the production casing may be formed of multiple sections joined together, and in certain instances the sections will have different diameters. In this way the casing diameter is able to narrow gradually towards the bottom of the well.
  • the fibre passes through the cement back fill, and is in fact clamped to the exterior of the metallic casing.
  • an optical fibre which is constrained in this instance by passing through the cement back fill, exhibits a different acoustic response to certain events to a fibre which is unconstrained.
  • An optical fibre which is constrained may give a better response than one which is unconstrained and thus in some embodiments it is beneficial to ensure that the fibre in constrained by the cement.
  • the difference in response between and constrained and unconstrained fibre may also be used as an indicator of damage to the cement which can be advantageous will be described later.
  • the fibre protrudes from the well head and is connected to interrogator/processor unit 112 .
  • the interrogator unit injects light into the fibre and senses radiation backscattered from along the length of the fibre.
  • the particular form of the input light and sampling/processing capability of the unit allows simultaneous output of multiple data channels, each channel corresponding to acoustic data sensed along a particular section of the fibre at a particular distance along the fibre. While the interrogator/processor unit is shown here as a single item, hardware may be divided among, for example, an interrogator box providing a raw data output, feeding a PC or portable computer to provide the data processing capability.
  • FIG. 2 An example of the type of possible data output from the arrangement of FIG. 1 is shown in FIG. 2 .
  • channel number (and hence depth for substantially vertical wells) is displayed along the y axis, with zero representing the channel nearest the surface. 400 channels are shown.
  • Time is displayed along the x axis as frame number, to provide a ‘waterfall’ plot which is continuously refreshed as new data is made available.
  • Detected energy intensity is shown as colour or greyscale in the upper plot 202 , using a scale shown on the right hand side to provide a 2D visualisation of the acoustic energy distribution along the entire sensed length of the fibre at each of a series of time instants.
  • the central plot 204 shows the same data after undergoing transient detection as will be explained in greater detail below, and the lower plot 206 shows the frequency of the detected transients according to the scale to the right of the plot.
  • the arrangement is such that data is available from all channels at every sample period.
  • depth from 0 to 4000 m is represented on the y axis, with time from 0 to 10000 s on the x axis
  • system It is proposed to use the system described above to monitor various downhole events including perforation, blanking plug and/or packer setting, fracture, proppant wash out and fluid flow.
  • system may provide general condition monitoring and, in some arrangements, may also allow communication with downhole sensors.
  • a fluid such as water
  • This fluid is therefore forced into the perforations and, when sufficient pressure is reached, causes fracturing of the rock along weak stress lines and to create and enlarge permeable paths for gas or other fluid to enter the well.
  • a solid particulate, such as sand, is typically added to the fluid to lodge in the fractures that are formed and keep them open.
  • a blanking plug is therefore inserted down the well to block the section of well just perforated. The perforating and fracturing process is then repeated at a different level.
  • the well starts production with product entering the casing from adjacent rock formations, and being transported to the surface.
  • a DAS sensor is used to monitor the perforation event.
  • Monitoring the perforation event can serve at least two distinct purposes. Firstly the location of the perforation can be determined. It can be difficult to control exactly the direction of the perforation in a borehole and so detecting the location of the perforation can aid in control and planning of further perforations. The ability to detect perforation type events will be described later. Also the acoustic signature of the perforation event may be compared to certain expected characteristics to determine whether the perforation occurred satisfactorily.
  • the perforation event is a relatively high energy event which acoustically excites a large proportion of the well bore, i.e. the casing, the cement, any blanking plugs already in place etc.
  • the acoustic response to a perforation event allows an acoustic profile of the well bore to be collected and assessed.
  • Acoustic data is sampled at between 0.2 Hz and 20 kHz over the length of the drilled hole during a perforation event.
  • the energy present in each channel is monitored by either a bandpass filter and then an rms energy calculation, or by performing an FFT and summing power between an upper and lower frequency band (typically 512 pt FFT, 50% overlapped, filtered between 300 and 5 kHz if sampling rate is practical).
  • An upper and lower frequency band typically 512 pt FFT, 50% overlapped, filtered between 300 and 5 kHz if sampling rate is practical.
  • a 2D data array of detected energy for time and depth (or position) can be produced.
  • the gradient of the identifiable trace can be measured, as it is the rate at which the energy is propagating through the well casing. This gives a measure of the transmission speed in the medium. This can be used to indicate areas of the well casing that are different because their transmission speed changes. This could indicate a problem with the casing attachment, or structural issues in the casing itself.
  • An automated tracking algorithm could be used to calculate the speed of this energy trace and determine areas where the speed changes.
  • an algorithm may work on the assumption that the event of interest is much larger than the normal state of the well, so that the peak in energy identified as the perforation event can be reliably identified. Then the peak can be associated over successive time frames, with the average speed over 1, 2, 3, . . . 10 s can be calculated. Further improvements could track multiple peaks at the same time (useful for distinguishing the main pulse in the case of multiple reflections).
  • FIG. 3 shows clear points of reflection of energy. These arise at joins in the casing and can provide an engineer with information concerning the quality of the joins across the length of the casing. Anywhere there is a significant mismatch in material, a partial reflection may occur, and the larger the mismatch, the greater is the reflection coefficient. Other material failures such as cracks or pitting could significantly affect the propagation of the energy along the casing and fibre, and be identified using this method.
  • the condition of the cement surrounding the casing may be assessed.
  • the acoustic response of the cement may vary in areas where there is a significant void in the cement, either due to manufacturing as the result of an earlier perforation or fracturing event.
  • Voids in the cement can be problematic because if a subsequent perforation occurs in an area of void when the proppant is pumped into the well bore it may not flow into the perforations in the rock but into the void—wasting a large amount of proppant and halting well formation whilst the problem is addressed.
  • the present invention may include detecting voids in the cement surrounding the casing.
  • the positioning and condition of blanking plugs can also be assessed in this way. If the blanking plug is not located correctly or is incomplete or weakened it may fail during the subsequent fracturing step.
  • a well condition profile can be built up in this way, providing data on the casing, cement fill, and blanking plugs if present.
  • the condition profile can be monitored over time to inform operators at various stages during well operation.
  • the well condition profile need not be limited to only those times where a perforation event occurs, and an alternative acoustic stimulus can be provided at a desired point in time as appropriate.
  • the proppant is flowed into the well to cause fracturing.
  • the proppant may not flow into the rock and proppant wash out may occur.
  • the flow of proppant in normal operation will generally proceed at a certain rate and with a certain characteristic. If the proppant finds another path or ceases to fracture correctly the flow conditions within the well may change. The acoustic response during proppant flow may therefore be monitored to detect any significant change.
  • Seismic and fracture events of interest are of a distinctly different nature from the continuous flow noise caused by the high pressure influx of water and sand during the fracturing process. Generally they are characterised by being short and impulsive events—hereafter referred to as transient events. A technique looking at short term variations away from the mean variable levels (the transient detector) will extract these events from background and long period noise.
  • the general processing method is set out in FIG. 4 .
  • a fracture event By processing the acoustic data received to highlight transient events in this way, a fracture event can be detected and observed, and the following parameters can be determined:
  • MAD (( N ⁇ 1)/ N )*MAD data+(1/ N )*abs(new Data ⁇ mean data)
  • the transient level is then defined as:
  • the algorithm adaptively selects an exponential factor according to whether a transient is triggered.
  • N in this example 100N is used
  • the location of fracture events may also be monitored to allow fracture mapping or fracture density mapping.
  • a typical production environment there may be several wells in the same oil or gas field. Ideally each well taps a different part of the field. However, it is possible for the fractures created in one well to run into the same area as the fractures from another well. In this instance the new well may not increase production as any production at the new well decrease production at the old well. It is therefore desirable to monitor the location of fractures.
  • the use of a DAS system offers the ability to detect and monitor where the fracture event are occurring in real time, thus allow control over the fracturing process.
  • DAS systems may be used separately to detect P and S waves.
  • P waves pressure or primary waves
  • S waves are shear waves or secondary waves which are transverse waves.
  • Co-pending patent application PCT/GB2009/002055 the contents of which are hereby incorporated by reference thereto, describes how a DAS system can be used to detect P and S waves and discriminate between them. Detecting the S waves of the fracture event may allow the location to be determined. To determine the location of the fracture event multiple fibres and/or time of arrival type techniques may be used as described in co-pending application no. GB0919904.3 the contents of which is hereby incorporated by reference thereto.
  • the S wave being a transverse wave
  • the S wave will have a shear direction associated with the wave. Detection of the different components of the S wave will allow a determination of the orientation of the fracture. This is particularly useful as fractures in the horizontal plane are not preferred as the injected sand is generally insufficient to keep the fracture open given the weight of rock above. A vertical fracture is thus preferred.
  • the incoming wave may be resolved into components in three dimensions. By arranging one or more sensing fibres in three dimensions the components of the incident wave may be resolved.
  • the use of a fibre optic which preferentially responds in one direction may help resolve an incident acoustic wave into its components, as described in co-pending application GB0919902.7 (cable design), the contents of which are hereby incorporated by reference thereto.
  • the configuration of the channels can also be adjusted, and different channel settings can be used for different monitoring operations.
  • the channel settings can also be adaptively controlled in response to monitored data, for example if a significant fracture density occurs at a certain depth, it may be desirable to monitor that particular depth with greater resolution for a period of time, before reverting to the original channel configuration.
  • a complete monitoring program can be run by a single system over a whole sequence of well operations from perforation to fluid inflow.
  • the system can be arranged to transition from one type of detection to another in response to detected events, and can adaptively vary both sensing and data processing parameters for a given monitoring/detection activity.
  • the DAS system may be used as a means of communicating with down-hole sensors.
  • US2009/0003133 describes a method of transmitting data from down well sensors and the like using acoustic using the casing itself as an acoustic medium.
  • the acoustic fibre may be used to receive encoded acoustic signals which means that lower power signals could be transmitted and done so reliably.

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US13/320,877 2009-05-27 2010-05-27 Well Monitoring by Means of Distributed Sensing Means Abandoned US20120063267A1 (en)

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GB0909038.2 2009-05-27
GB0909038A GB0909038D0 (en) 2009-05-27 2009-05-27 Well monitoring
GB0919915.9 2009-11-13
GB0919915A GB0919915D0 (en) 2009-11-13 2009-11-13 Well monitoring
PCT/GB2010/001064 WO2010136773A2 (en) 2009-05-27 2010-05-27 Well monitoring

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US13/320,884 Active 2033-08-17 US9617848B2 (en) 2009-05-27 2010-05-27 Well monitoring by means of distributed sensing means
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