WO2017178065A1

WO2017178065A1 - Method for increasing the sensitivity and versatility of optical das sensors

Info

Publication number: WO2017178065A1
Application number: PCT/EP2016/058353
Authority: WO
Inventors: Jakob B. HALDORSEN
Original assignee: Read As
Priority date: 2016-04-15
Filing date: 2016-04-15
Publication date: 2017-10-19

Abstract

Optical seismic sensor system 10 for acquiring seismic data having multi-directional sensitivity comprising one continuous length of an optical fibre 20 arranged as a distributed acoustic sensor, an interrogator 30 with a transmitter for transmitting optical pulses into the optical fibre 20, a receiver for receiving reflected optical pulses, and an interpreter for interpreting reflected optical pulses. It further comprises at least one sensor head 40 having flexural properties and multi-directional sensitivity, and where a section of the continuous length of the optical fibre 20 is wound onto a part of the sensor head 40 having the having flexural properties. A method for providing such a system is also defined.

Description

METHOD FOR INCREASING THE SENSITIVITY AND VERSATILITY

OF OPTICAL DAS SENSORS

INTRODUCTION

The invention relates to a method for acquisition of seismic data, and more specifically to an optical seismic sensor system and a method for acquiring seismic profiles.

BACKGROUND

Within the field of acquisition of seismic data, Vertical Seismic Profiling (VSP) is a technique using seismic measurements where data generated by an acoustic source at the surface are recorded by receivers deployed in a well. A receiver close to the target will record the wave field incident on the target and, after a time delay, also the wave field scattered off the target. Relating these two wave-field components gives formation images of greater detail and resolution, as well as more

independence from detailed knowledge of the formation between the source and the receivers. Although inherent in all standard processing of VSP data, this

relationship is formalized in the interferometric approach to seismic data analysis (Bakulin and Calvert, 2004).

The multi-level aspect of a receiver array will allow the estimation of the delay from one receiver to the next while the wave front is passing from one end of the array to the other. A 3C receiver also measures the local direction of particle motion related to components of the passing wave fields. A multi-level 3C receiver array can therefore be used to find estimates of both the full waveform and the direction of propagation in 3D space of any passing plane waves, arriving either directly from the source or scattered by the formation. If the formation velocities are known at some level of accuracy, the time delays and polarizations at the array of receivers are sufficient for identifying whether the passing wave was compressional or shear (Leaney and Esmersoy, 1989), the ray direction, and the distance along the ray back to the source, or the location of a natural or induced seismic event as the place where the compressional and shear waves coincide in time and space (e.g.,

Haldorsen et al., 2013).

Whereas measuring both the source and scattered fields close to the target gives formation images of higher resolution, the spatial extent of the formation image becomes much narrower. To counteract this, it is desirable to combine receivers that are close to the object with receivers that are further away. For wave-field measurements it is also a requirement of at least two measurements per wavelength of the acoustic wave. With a wavelength of typically 30 m for compressional waves (and half of that for shear), one would need to deploy a rather large number of receivers. For a target at 4000 m depth, it would require at least 280 discrete 3C receivers to instrument the well to the surface.

Traditionally, 3D VSP imaging has been done with an array of 40-100 receiver levels, with the array placed about midway between the target formation and the surface. This position gives reduced propagation paths and improved resolution compared to surface seismic data and a reasonable lateral image aperture. Pre- survey modelling is used to determine the best compromise for the depth of the array for given objectives for resolution and lateral aperture of target illumination.

Distributed Acoustic Sensing (DAS) is another technology using a simple optical fibre as the sensing element. This solution offers the capability to simultaneously sample at thousands of measurement points, giving a massive acoustic sensor antenna. An impinging acoustic wave will lead to local changes in the longitudinal and axial strains in the optical fibre. By recombining two optical pulses within a given time that defines the gauge length of the sensor, optical phase change due to the strains and elasto-optic interaction can be detected with a high resolution.

Continually monitoring the phase, amplitude and wavelength of the received signal and using the unstrained fibre as a baseline, acoustic waves interfering with the cable and inducing strain can be monitored by means of an optical interrogator. An optical interrogator is part of a surface acquisition system, and an optical sensor would not have down-hole electronics and could therefore be used at higher temperatures than an electric sensor.

The measurement of dynamic strain in a traditional fibre at discrete points is similar to a single component (1C) geophone at each point aligned in the direction of the fibre. Conventional electrically-driven geophones are considered to be better than DAS sensors with respect to signal-to-noise ratio. However, recent developments appear to be closing the gap.

In its basic form, DAS only measures the strain changes along the axis of an optical fibre. However, by combining them with mechanically restrained devices, one can measure acceleration in directions other than the main axial direction of the fibre. These are called multi-directional sensors. For commercially available three component (3C) optical sensors, each sensor is typically built up from 40 to 50 m of fibre coiled around a device which is mechanically restrained, allowing the mechanical device to translate acceleration in one particular direction to a strain in the fibre coiled around the mechanically restrained sensor device. Figure 12 in US 9207339 shows an example of such a device.

The mechanics of a weighted core of a coil allows the coil to only move and accelerate in one particular direction, and only movement in that direction will generate strain on the fibre, the change of which is what a DAS interrogator measures. The DAS interrogator will record this directional strain at the location of the sensor.

Using inter ferometric processing, this strain is compared to an identical, but unstrained fibre coil. However, this typically requires a complex system with downhole laser splitters and mirrors. With some commercially available 3C optical sensors, the laser-light available allows up to 9 channels per fibre, i.e. three 3C sensors per fibre. For 120 levels, this would thus require 40 continuous fibres.

According to the present invention it is suggested to view the multi-directional sensors and the fibre connecting them as one continuous fibre and read the accumulated strain through the fibre coils with a DAS interrogator. Viewing the fibre as one single fibre, continuing through the coils, one may use the same interrogator to read both 1C and 3C sensor elements. This will allow more 3C sensor elements, and with less fibres in the cable.

This will allow more multi-directional sensors and less use of fibre in the cable. It would also eliminate the need for down-hole laser splitters and mirrors.

The maximum range of a DAS interrogator is of the order of 40 km before there is insufficient reflected laser light allowing a reasonable estimate of fibre strain. With 15 m between the sensors (each sensor requiring 15+3 *50 = 165 m of fibre), if one could use the DAS interrogator to read the coiled fibre in an optical 3C sensor, one could fit about 240 sensors into a 4 km long cable, or 600 onto a 9 km using one fibre for each of the x, y and z components, for a total of 720 or 1800 channels - in practical terms there is no limit.

Using all-optical sensors in a well, based on one single optical fibre, will eliminate the need for electrical power and electronics required in a wellbore installation of a conventional electrical 3C Vertical Seismic Profiling (VSP) receiver system.

Adding the 3C measurement will allow the resolution of the azimuthal ambiguity inherent in the DAS measurement, and this will significantly improve the capabilities both for VSP and for permanent down-hole, high-resolution, acoustic monitoring of producing oil fields. Complete and finely spaced well coverage with acoustically sensitive sensors also provides continuous real time monitoring of mechanical integrity and detect early signs of abnormal well activity.

SUMMARY OF THE INVENTION

The invention is defined by an optical seismic sensor system for acquiring seismic data having multi-directional sensitivity comprising one continuous length of an optical fibre arranged as a distributed acoustic sensor comprising an interrogator. The interrogator comprises a transmitter for transmitting optical pulses into the optical fibre, a receiver for receiving reflected optical pulses, and an interpreter for interpreting reflected optical pulses. The optical seismic sensor system further comprises at least one sensor head having flexural properties and multi-directional sensitivity, and where a section of the continuous length of the optical fibre is wound onto a part of the sensor head having the flexural properties.

The invention is also defined by a method for acquiring seismic data by employing the optical seismic sensor system described above.

Different embodiments of the invention is defined in the claims.

DETAILED DESCRIPTION

The present invention is a fully-optical, hybrid acoustic sensor cable, using 3C optical sensors placed at intervals along the cable measuring local acoustically- induced directional strain combined with near-continuous 1C optical DAS sensors, both measuring acoustically induced axial strain on the one and same optical fibre.

For permanent installation in low-to -mo derate temperature wells, a system combining traditional 3C electrical sensors with 1 C optical sensors is suitable, and where a continuous optical fibre connection can be made to an offshore platform. The down-hole electronics needed for the electric 3C sensors will however adversely affect the expected lifetime, especially in a higher temperature well.

The all-optical hybrid sensor cable according to the invention, will have no electronics in the hot zone of the well, and will therefore not be affected in a significant way by high temperatures. The operational temperatures are expected to exceed 200°C by a good margin.

The present invention will now be described in detail with reference to the drawings where:

Figure 1 illustrates an optical seismic sensor system according to the invention, and

Figure 2 illustrates details of a sensor head according to one embodiment of the invention.

In view of prior art, there is a need for a cost effective and flexible seismic sensor system for acquiring seismic data having multi-directional sensitivity. The present invention provides this system by combining two separate fibre-optical, acoustic measurement techniques on a single optical fibre. These are:

1) Distributed Acoustic Sensors (DAS) giving a near-continuous measurement of the component of an acoustic field along the axis of an optical fibre.

2) Three-component (3C) measurements from special, directional optical sensors, distributed more coarsely along the optical cable. Figure 1 illustrates an optical seismic sensor system where two different acoustic measuring techniques are combined for reducing the cost and improving the flexibility of the instrumentation installed.

More specifically, the figure illustrates an optical seismic sensor system 10 for acquiring seismic data having multi-directional sensitivity comprising one continuous length of an optical fibre 20 arranged as a distributed acoustic sensor, an interrogator 30 with a transmitter for transmitting optical pulses into the optical fibre 20, a receiver for receiving reflected optical pulses, and an interpreter for interpreting reflected optical pulses. These components are well known in the art of Distributed Acoustic Sensors (DAS).

The novel features are that optical seismic sensor system 10 further comprises at least one sensor head 40 having flexural properties and multi-directional sensitivity, and where a section of the continuous length of the optical fibre 20 is wound onto a part of the sensor head 40 having the flexural properties.

The figure illustrates one embodiment of an all optical system having multidirectional measuring properties, where several multi-directional sensor heads 40 are evenly distributed along the optical fibre 20, and where sections of the continuous length of the optical fibre 20 are wound onto a part of each multidirectional sensor head 40 having flexural properties.

A seismic sensor system 10 according to the invention is not restricted to the four multi-directional sensor heads 40 shown in figure 1. It may be at least one, but preferably a plurality, e.g. 600 on a 9 km optical fibre 20.

Using all-optical sensors will eliminate the need for electrical power and electronics required in a wellbore installation of a conventional electrical 3C Vertical Seismic Profiling (VSP) receiver system. Adding the 3C measurement will allow the resolution of the azimuthal ambiguity inherent in the DAS measurement, and will significantly improve the capabilities both for VSP and for permanent down-hole high-resolution, acoustic monitoring of producing oil fields. Complete and finely spaced well coverage with acoustically sensitive sensors also provides continuous real time monitoring of mechanical integrity and detect early signs of abnormal well activity.

It is well suited for being permanently installed in a well to acoustically monitor injection or production in the well and the productive zones that surround it.

To manage a producing hydrocarbon reservoir continuously, surveillance data need to be acquired in real time in order to build a 3-dimensional image or map of the injected or produced fluid saturations and migration pathways around the wellbore. In addition, the vertical resolution needs to allow adequate isolation of zones that relate to fluid pathways and well productivity. 4D seismic analysis is the best means for determining saturations and also for generating dynamic reservoir images between wells that allow reservoir monitoring to assess the effects of production. However, the data acquisition and processing required for 4D seismic analysis are both costly and time consuming. Therefore, the number of times 4D seismic data are acquired during the life of a field is very limited. With an array of acoustic sensors permanently installed in the borehole, 3D VSP data can be acquired on demand, and 4D images of the reservoir around the well can be generated in a timely and cost effective manner. These images will provide information on sweep efficiencies, thief zones, potential zones of early breakthrough, injection conformance, potential identification of well safety issues amongst other applications that all contribute to improvements in well efficiency and safety.

The multi-directional sensor heads 40 and the optical fibre 20 wound onto it act as receivers of seismic activity. With such receivers placed close to the reservoir, this method of surveillance can continuously monitor weak acoustic activities induced by the production process, allowing preventive action to be taken if critical situations should arise. Having the receivers close to the reservoir would also allow for higher-resolution imaging as the acoustic source field and the scattered field both are observed close to the imaging target. Earth movements related or unrelated to production/injection can generate small earthquakes that can only be monitored with sensors close to the micro-earthquake activity and only be located with 3C sensors.

A hybrid optical acoustic sensor cable according to the invention would allow the generation of 4D images of a formation around a well at lower costs when compared to surface methods. Due to the nature of fibre-optical sensing, the system will have long lifetime in higher-temperature wells and can also be installed in subsea- completed deep-water wells.

Using only reflections from natural impurities in the fibre, the amount of light returned per length unit of fibre is very small. In order to increase the return from the point sensors, and to minimize the amount of fibre coiled up around the mechanical sensor head 40, one embodiment of the invention defines a feature where discrete partial reflectors are implanted in the optical fibre 20.

Such reflectors may in one embodiment be Bragg gratings 50 that are engraved on the optical fibre 20 immediately before and after the sensor head 40. This will also reduce the required length of fibre coiled around the mechanical device. A typical reduction from 50m to 10m of fibre in the coil of each 3C point sensor is expected.

Figure 2 illustrates this principle where the part of the optical fibre 20 that is wound on the at least one directional sensor head 40 is provided with engraved Bragg gratings 50 immediately before and after the sensor head 40. This will allow a reduction in the length of fibre coiled around the mechanical device to typically less than 1/5. If the Bragg grating 50 is designed to reflect only a small fraction, e.g., 0.1 percent, of the laser light, this will allow hundred's of high- return 3C point sensors on one single optical fibre 20.

By implanting discrete partial reflectors in the fibre, the sensitivity and versatility of optical sensors will increase locally. As an alternative to Bragg gratings 50, Michelson interferometers using directional couplers and mirrors may be used. Like with the 3C electric geophones, fibre-optical accelerometers can be designed with directionality and substantially higher strain response compared with a fibre encapsulated in an in- well cable. Such accelerometers can be arranged in a 3C package/station suitable for high-resolution multi-component seismic imaging.

Appropriate design of a system according to the present invention gives higher sensitivity of 3C optical sensors compared to conventional electric acoustic sensors, and they are otherwise considered an improvement in view of electrical geophones.

Claims

An optical seismic sensor system (10) for acquiring seismic data having multi-directional sensitivity comprising one continuous length of an optical fibre (20) arranged as a distributed acoustic sensor, an interrogator (30) with a transmitter for transmitting optical pulses into the optical fibre (20), a receiver for receiving reflected optical pulses, and an interpreter for interpreting reflected optical pulses,

c h a r a c t e r i z e d i n further comprising:

at least one sensor head (40) having flexural properties and multi-directional sensitivity, and where a section of the continuous length of the optical fibre (20) is wound onto a part of the sensor head (40) having the flexural properties.

The optical seismic sensor system (10) according to claim 1 , where several multi-directional sensor heads (40) are evenly distributed along the optical fibre (20), and where sections of the continuous length of the optical fibre (20) are wound onto a part of each multi-directional sensor head (40) having flexural properties.

The optical seismic sensor system (10) according to claim 1 or 2, where the part of the optical fibre (20) which is wound on the at least one sensor head (40) is provided with engraved Bragg gratings (50) immediately before and after the sensor head (40).

A method for acquiring seismic data by employing an optical seismic sensor system (10) having multi-directional sensitivity comprising one continuous length of an optical fibre (20) arranged as a distributed acoustic sensor, an interrogator (30) with a transmitter for transmitting optical pulses into the optical fibre (20), a receiver for receiving reflected optical pulses, and an interpreter for interpreting reflected optical pulses,

c h a r a c t e r i z e d i n further employing at least one sensor head (40) having flexural properties and multi-directional sensitivity and winding a section of the optical fibre (20) on a part of the sensor head (40) having flexural properties; transmitting optical pulses into the optical fibre (20) by means of the interrogator (30);

- receiving and interpreting reflected pulses from the distributed

acoustic sensor channels along the optical fibre (20) and combining these with sets of optical pulses reflected from the part of the optical fibre (20) which is winded on the sensor head (40).

The method according to claim 4, by employing several multi-directional sensor heads (40) and distributing them evenly along the optical fibre (20), and winding sections of the continuous length of the optical fibre (20) onto a part of each multi-directional sensor head (40) having flexural properties.

The method according to claim 4, by providing Bragg gratings (50) on the part of the optical fibre (20) which is immediately before and after the part of the optical fibre (20) which is wound on the at least one sensor head (40).

The method according to any of claims 4 to 6, where the at least one sensor head (40) of the seismic sensor system (10) is connected to a formation via a casing or tubing.

The method according to any of claims 4 to 7, where the seismic sensor system (10) is arranged for permanent monitoring of injection or production in a well.