US20170096890A1

US20170096890A1 - Ranging While Drilling Using Optical Fiber Sensors

Info

Publication number: US20170096890A1
Application number: US14/876,693
Authority: US
Inventors: Arthur H. Hartog; Karim Boudah; Miguel F. Pabon
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2015-10-06
Filing date: 2015-10-06
Publication date: 2017-04-06

Abstract

A system and methods for drilling a well in a field having an previously drilled well are provided. In accordance with one example, a method includes drilling a new well in a geological formation having an previously drilled well using a bottom hole assembly (BHA) having a transmitter. The method also includes transmitting a signal while drilling using the transmitter of the BHA. Further, the method includes measuring from the previously drilled well the signal from the transmitter received by at least one optical fiber disposed within the previously drilled well.

Description

BACKGROUND

This disclosure relates to well drilling operations in which measurements from an optical fiber are used to ascertain a relative location of a new well to a previously drilled well.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.
Heavy oil may be too viscous in its natural state to be produced from a single well. Instead, two or more wells may be drilled near to one another. In a technique referred to as Steam Assisted Gravity Drainage (SAGD), an “injector well” injects steam to heat the heavy oil, which causes the heavy oil to become much less viscous. Another well known as a “production well,” which is situated beneath the injector well, collects the heated heavy oil. For an SAGD well pair including an injector well and a production well, the injector well is a horizontal well located above and oriented substantially parallel to the production well.
To increase the amount of heavy oil that is recovered from an SAGD well pair, steam from the injector well is injected at a precise point in the heavy oil formation. Indeed, if steam is injected too near the production well, steam may be shunted out of the formation and into the production well instead of heating the heavy oil. Moreover, if the wells are located too far from one another, the heated heavy oil may cool down, and therefore may become too viscous, to be recovered in the production well. Yet maintaining an appropriate distance while drilling the production and injector wells may be difficult. Additionally, a trajectory of the first well that is drilled (e.g., the production well) may be inconsistent, increasing the difficulty of maintaining the appropriate distance while drilling the second well (e.g., the injector well).

SUMMARY

A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.
In one example, a method includes drilling a new well in a geological formation having a previously drilled well using a bottom hole assembly (BHA) having a transmitter. The method also includes transmitting a signal while drilling using the transmitter of the BHA. Further, the method includes measuring from the previously drilled well the signal from the transmitter received by at least one optical fiber disposed within the previously drilled well.
In another example, a drilling system includes a bottom hole assembly (BHA) including a transmitting device. The transmitting device transmits a signal from the BHA while drilling a new well. Additionally, the drilling system includes at least one optical fiber disposed within a previously drilled well that interacts with the signal transmitted from the transmitting device. Further, the drilling system includes a polarization detector coupled to the at least one optical fiber to measure a polarization state of light within the at least one optical fiber.
In another example, a method of drilling a well includes drilling a second horizontal well above a first horizontal well using a bottom hole assembly (BHA) having a transmitting device. The method also includes transmitting a signal from the transmitting device while drilling the second horizontal well. Additionally, the method includes measuring from an optical fiber within a first horizontal well the signal from the transmitting device.
Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated examples may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of examples of the present disclosure without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present subject matter may become apparent upon reading the following detailed description and upon reference to the drawings in which:

FIG. 1 is a schematic of a drilling operation using passive ranging while drilling a parallel well;

FIG. 2 is a flow chart depicting an example of a method of performing the drilling operation of FIG. 1;

FIG. 3 is a schematic of a production well and an injector well of the drilling operation of FIG. 1;

FIG. 4 is a schematic cross-section depicting the production well and the injector well of FIG. 3;

FIG. 5 is a cross-sectional view of an example of a production well and a sand screen within the production well;

FIG. 6 is a perspective view of a slotted casing; and

FIG. 7 is a schematic example of a polarimetric sensing array for an optical fiber coupled to the casing of the production well.

DETAILED DESCRIPTION

One or more examples of the present subject matter are described below. It may be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions are made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it may be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
In well drilling operations, it may be desirable to place wells close together or in specific orientations relative to one another. In steam assisted gravity drainage (SAGD) operations, for example, well pairs are generally positioned parallel and close together to facilitate production of heavy oil. Additionally, it may be desirable in other drilling operations to position a series of wells in a specific orientation relative to one another. For example, it may be desirable to drill a number of parallel wells in a row. Well drilling operations, such as SAGD operations and the like, generally use some type of ranging technique, other than conventional MWD surveying techniques that generally report inclination and azimuth, to establish orientations and distances between the wells.
Accordingly, embodiments of the present subject matter are directed to systems and methods for drilling two or more wells while maintaining a positional relationship between the wells, such as a specific distance between the walls of each well. In particular, present embodiments are directed to drilling a new well by maintaining a specific distance from a previously drilled well using measurements from an optical fiber within the previously drilled well. For example, by providing a ranging technique that uses measurements from an optical fiber, present embodiments may use several signals provided by a drilling operation of the new well to determine a distance between the new well and the previously drilled well.
FIG. 1 depicts a drilling operation 10 involving ranging while drilling. In the drilling operation 10, a previously drilled production well 12 and a new injector well 14 currently being drilled extend from the surface through a formation 16 into a heavy oil zone 18. The production well 12 and the injector well 14 may be horizontal wells that are at least partially horizontal in places (i.e., not completely vertical). Additionally, the production well 12 may operate with a pump jack 20, and the injector well 14 includes a drilling rig 22. The production well 12 is cased with casing 24 and may be completed with a slotted casing 26 and one or more optical fibers 28. A drill string 30 is used to drill the injector well 14. The drill string 30 includes a bottom hole assembly (BHA) 32 having a drill bit 34 and a steerable system 36. The BHA 32 may also include a variety of drilling tools such as a measurement while drilling (MWD) tool or a logging while drilling (LWD) tool.
A transmitter 38 in the BHA 32 may transmit current into the heavy oil zone 18 and generate an azimuthal electromagnetic field 40 emanating from the drill string 30. The electromagnetic field 40 may be transmitted in a specific form (e.g., a signal having known characteristics such as DC component value, frequency, modulation, etc.) to help distinguish signals from the transmitter 38 from ambient electromagnetic noise. The optical fibers 28 deployed along the production well 12 may provide a continuous measurement device along a length of the production well 12 that includes the optical fibers 28. Further, the optical fibers 28 may be affixed within the production well 12. By measuring a strength of the electromagnetic field 40 with the optical fibers 28, the relative position between the production well 12 and the injector well 14 may be ascertained. Further, in some instances, the azimuthal electromagnetic field 40 may be generated from electromagnetic radiation resulting from fields generated by rotation of the drill bit 34. That is, the transmitter 38 may be replaced or supplemented by electromagnetic radiation generated from the drill bit 34.
Further, as discussed in detail below, the transmitter 38 may also be an acoustic transmitter. In such a situation, the transmitter 38 may generate acoustic signals that are detected by the optical fibers 28 to help ascertain the relative position between the production well 12 and the injector well 14. Additionally, as with the electromagnetic field 40, noise generated by the drill bit 34 during the drilling of the injector well 14 may also replace or supplement the acoustic signals provided by the transmitter 38 to be detected by the optical fibers 28.
Additionally, the optical fibers 28 may also be used to detect temperature within the production well 12. For example, temperature may be detected by the optical fibers 28 by measuring an intensity of Raman scattered light or frequency and/or intensity of Brillouin-shifted light within the optical fibers 28. Additionally, analysis of Rayleigh backscattering of optical signals in the optical fibers 28 may also be used for temperature-distributed measurements. Measuring and monitoring temperature changes within the production well 12 may signal characteristics about the production well 12 that are beneficial to oil production. For example, a temperature change may signal a blockage within a wellbore preventing production of oil from the heavy oil zone 18. Further, it may be appreciated that a light source may provide pulses of light into the optical fibers 28 at a known pulse rate.
Furthermore, it may be appreciated that while the techniques described herein generally relate to ranging between the injector well 14 and the production well 12, the techniques may also be used to drill a relief well to intersect an existing well. Additionally, the techniques may also be used to avoid drilling one well into another existing well. For example, this may be beneficial when drilling from a crowded platform to avoid drifting into another well near the surface. Moreover, the techniques described herein also generally relate to the optical fibers 28 disposed within the production well 12. However, it may be appreciated that the injector well 14 may be drilled initially, and the optical fibers 28 may be disposed within the injector well 14. In such a situation, the optical fibers 28 may measure signals from a drilling operation of the production well 12 to determine the relative positioning of the production well 12 and the injector well 14.
FIG. 2 provides a flow chart of a method 42 for performing the drilling operation 10 of FIG. 1. At block 43, the production well 12 is drilled through the formation 16 and into the heavy oil zone 18. Drilling the production well 12 may be accomplished using any suitable techniques. Additionally, the production well 12 may be drilled with or without reference to another well and using any suitable steerable drilling techniques.
After drilling the production well 12, block 44 involves installing the casing 24 and a completion string in the production well. Additionally, block 44 also involves installing the optical fibers 28 along the casing 24 and/or the completion string. As discussed above, the optical fibers 28 may be used to determine a relative location of the injector well 14 to the production well 12 while the injector well 14 is drilled.
Subsequently, at block 46, the injector well 14 is drilled. As mentioned above, the steerable system 36 of the BHA 32 is used to steer the direction of the drill bit 34. Further, when the electromagnetic field 40 or an acoustic signal interacts with light pulses that are pulsed within the optical fibers 28, a location of the transmitter 38 in relation to the production well 12 is determined. For example, at block 48, the transmitter 38 and/or drilling noise is used to excite the optical fiber 28 in the production well 12 with the electromagnetic fields 40 and/or acoustic signals. A polarization state and/or a phase change may be determined for light pulses that travel within sections of the optical fiber 28. By determining the polarization state of the light in various sections of the optical fiber 28, an operator is able to determine a strength of the electromagnetic fields 40 or the acoustic signals that are interacting with the light.
For example, at block 50, the electromagnetic fields 40 or the acoustic signals may be measured within the production well 12. In one instance, an axial magnetic field may cause a rotation of the polarization state of the light travelling within the optical fiber 28 through the Faraday Effect. By measuring the rotation of the polarization state and/or measuring the phase changes, the strength of the electromagnetic fields 40 that act upon the light in the optical fiber 28 may be determined. Additionally, if the electromagnetic fields 40 are insufficient for a reading on the optical fiber 28, a magnetic field concentrator may be deployed along a length of the optical fiber 28 to direct more of the electromagnetic field 40 to pass through the optical fiber 28. Further, it may be appreciated that the polarization state may be measured using polarization optical time-domain reflectometry (POTDR).
By measuring the electromagnetic fields 40 or the acoustic signals, at block 52, an operator may be able to use various ranging techniques to determine a position of the injector well 14 in relation to the production well 12. For example, the operator may determine based on the polarization state measurement that the drill bit 34 within the injector well 14 is drilling on a trajectory either too close or too far away from the production well 12. This may give the operator an indication that the trajectory of the drill bit 34 may be adjusted to maintain a constant distance from the production well 12.
In this manner, at block 54, the steerable system 36 of the BHA 32 may be able to maintain a drilling path that keeps a constant distance between the injector well 14 and the production well 12. In some circumstances, this may be a separation of approximately 5 meters. However, in other circumstances, the constant distance between the injector well 14 and the production well 12 may be greater than or smaller than 5 meters depending on different characteristics of the injector well 14 or the production well 12, as well as physical and chemical characteristics of the formation 16 and the heavy oil zone 18. For example, it may be beneficial to maintain a smaller or greater distance between the production well 12 and the injector well 14 based on a viscosity of heavy crude oil and bitumen within the heavy oil zone 18.
Turning to FIG. 3, a more detailed view of a schematic of the production well 12 and the injector well 14 depicts the drilling operation 10 of FIG. 1. In the illustrated example, the BHA 32 of the drill string 30 includes the transmitter 38 that generates the electromagnetic field 40 as well as a transmitter 56 that generates an acoustic signal 58. The acoustic signal 58 may interact with the light within the optical fibers 28 of the production well 12 in a manner similar to the electromagnetic field 40. Accordingly, by transmitting both the electromagnetic field 40 and the acoustic signal 58, additional positioning information may be obtained at the optical fibers 28 relating to the position and/or drilling dynamics of the injector well 14. Additionally, it may be appreciated that determining the relative position between the production well 12 and the injector well 14 may also be accomplished using the acoustic signal 58 by itself or the electromagnetic field 40 by itself.
Further the drilling dynamics, in particular, may be determined from measuring the acoustic signal 58. Additionally, the acoustic signal 58 may originate from noise produced by the drill operation 10. For example, instead of using the transmitter 56 to generate the acoustic signal 58, the noise produced by the drill bit 34 may be detected by the optical fibers 28. Using this method, the measurements of the interaction between the acoustic signal 58 and the light within the optical fibers 28 may provide information relating to whether the drill bit 34 is sliding (i.e., drilling using a drilling motor absent rotation of the drill string 30) or drilling by rotating the drill string 30 from the surface, whether the drill string 30 is off-bottom or on-bottom, whether the drill string 30 experiences smooth rotation or stick-slip rotation, and whether the rotation is forward moving or reverse moving. By classifying acoustic signatures of each of these drilling dynamics, an operator may know what effect the acoustic signatures have on the light pulses within the optical fibers 28, and ultimately inform the operator about present drilling dynamics of the drill operation 10. Further, if the drilling is stuck, the electromagnetic field 40 and/or the acoustic signal 58 may provide an indication of the location at which the drilling is stuck. Using this technique, increased automation of the drilling process may be available.
To measure the acoustic signal 58, a distributed vibration sensor (DVS) may be used to measure vibration generated by the acoustic signal 58 as the acoustic signal approaches the optical fibers 28. The distributed vibration sensor may measure changes in pulses of light sent through the optical fibers 28 as the pulses return to a light source. The changes in the pulses (e.g., phase changes or polarizations states) enable an operator to determine the relative locations of the production well 12 and the injector well 14 as well as the drilling dynamics while drilling the injector well 14. Additionally, there may be some ambiguity as to an azimuth of the production well 12 relative to the injector well 14. Accordingly, it may be beneficial to include the optical fibers 28 in other nearby wells to define a location of the acoustic signal 58 in three dimensions. Moreover, including the optical fibers 28 in other nearby wells may also define a location of the electromagnetic field 40 in three dimensions.
Additionally, by comparing a time of arrival of noise from the drill operation 10 at different locations along the optical fibers 28, a distance between the injector well 14 and the production well 12 may be ascertained using a form of triangulation. In a similar manner, a phase of the acoustic signal 58 may be compared as a function of position along the production well 12, in which the optical fibers 28 are located, to estimate both penetration of the drill bit 34 (i.e., how far along a borehole the drill bit 34 is located) and the distance between the injector well 14 and the production well 12. Additionally, the acoustic signal 58 may be noise generated by the drill operation 10 as well as supplemented or replaced by acoustic signals generated from the transmitter 56. For example, it may be desirable to use higher frequency acoustic signals 58 than are naturally present from the drill operation 10 when the production well 12 and the injector well 14 are in close proximity to each other to improve distance estimation accuracy.
Further, it may be appreciated that distribution vibration sensors (DVS's) may not distinguish a direction of arrival. For example, the distribution vibration sensors may be sensitive to the acoustic signals 58 on a parallel axis and progressively less sensitive to the acoustic signals 58 as a direction of arrival becomes more perpendicular to an axis of the optical fibers 28. Accordingly, in some examples, the optical fibers 28 may continue to a vertical portion of the production well 12 to maintain the acoustic signals 58 on the parallel axis while drilling a vertical portion of the injector well 14.
In addition to measuring the electromagnetic fields 40 or the acoustic signals 58, the optical fibers 28 may also be used for other location-determining measurements. For example, strain on the optical fibers 28 caused by distortion of the earth resulting from nearby drilling operations may also be measured. Additionally, the detection at the optical fibers 28 could passively result from the drill operation 10 (e.g., using sound strain or magnetic disturbance from drilling), or the detection at the optical fibers 28 could result from the active transmitters 38 or 56 (e.g., electromagnetic fields 40 or acoustic signals 58) placed on the drill string 30 of the BHA 32. Further, installing the optical fibers 28 in multiple wells relatively close to a drilling location for the injector well 14 may result in increased accuracy about the location of the drilling operation 10 or the transmitters 38 and 56.
Also illustrated is the slotted casing 26 of the production well 12. The slotted casing 26 includes multiple slots machined into a casing. The slots of the slotted casing 26 allow fluid to pass while preventing other materials from collapsing into a borehole while the production well 12 pumps oil to the surface. Additionally, a constant distance 62 between the injector well 14 and the production well 12 may be beneficial. In some instances the constant distance 62 may be approximately 5 meters. Further, as mentioned above, the constant distance 62 may be more than or less than 5 meters depending on geological properties of the heavy oil zone 18 and/or production preferences of the operator.
FIG. 4 illustrates a cross-sectional view of the schematic representation of the production well 12 and the injector well 14 of FIG. 3. As discussed above, the transmitters 38 or 56 transmit the electromagnetic field 40 or the acoustic signal 58 radially outward from the drill string 30 within the injector well 14. The electromagnetic field 40 or the acoustic signal 58 may interact with light pulsing within the optical fibers 28 of the casing 24 in the production well 12.
In the illustrated example, the casing 24 is surrounded by four of the optical fibers 28. It may be appreciated that there may be any number of the optical fibers 28 surrounding the casing 24 during implementation of the drilling operation 10. For example, there may be as few as one of the optical fibers 28 surrounding the casing 24, or there may be ten or more of the optical fibers 28 surrounding the casing 24 during the drilling operation 10.
Further, the optical fibers 28 are illustrated as surrounding the casing 24 on an outside portion of the casing 24. However, the optical fibers 28 may also be arranged within pre-arranged depressions along the slotted casing 26. The pre-arranged depressions may provide protection for the optical fibers 28 while the casing 24 is installed within the production well 12. Additionally, in some circumstances, it is contemplated that the optical fibers 28 may also be arranged along an inner-portion of the casing 24.
Turning to FIG. 5, a cross-sectional view is depicted of an example of the production well 12 and the casing 24 within the production well 12. As illustrated, the production well 12 is cased with the casing 24 after completing the drilling of the production well 12. The casing 24 may include a sand screen 67 and a screen shroud 65. The screen shroud 65 and the sand screen 67 may prevent particulate matter from entering a borehole 63 while still allowing hydrocarbons to enter the borehole 63. In other embodiments, as discussed above, the casing 24 may include the slotted casing 26, and the sand screen 67 may be removed. The casing may also include shunt tubes 64. The shunt tubes 64 provide an alternative flow path for a gravel pack 66 mixture that enables the gravel pack 66 to provide complete coverage of the gravel pack 66 around the sand screen 67 and within the production well 12.
Further, the optical fiber 28 is shown as positioned within a pre-arranged depression 68, which runs along a length of the casing 24. The pre-arranged depression 68 may provide protection for the optical fiber 28 while the casing 24 is installed. Additionally, the pre-arranged depression 68 may be created during installation. For example, the pre-arranged depression 68 may form around the optical fiber 28 as the casing 24 is installed. By placing the optical fiber 28 within the pre-arranged depression 68, a risk of damaging the optical fiber 28 during installation of the casing 24, and during general operation of the production well 12, may be reduced.
FIG. 6 is a perspective view of an example of the slotted casing 26 including a depiction of the pre-arranged depression 68 that receives the optical fiber 28 upon installation. It may be appreciated that while one pre-arranged depression 68 is illustrated, the slotted casing 26 may include several of the pre-arranged depressions 68 around an outer circumference of the slotted casing 26. Additionally, in some circumstances, the slotted casing 26 may include several of the pre-arranged depressions 68, but, upon installation of the casing 24, one or more of the pre-arranged depressions 68 may not be populated with the optical fiber 28. Further, a coupling device 70 may also be positioned within the pre-arranged depressions 68. The coupling device 70 may enable coupling of the optical fibers 28 to the slotted casing 26 to minimize movement of the optical fibers 28 during installation of the slotted casing 26 and operation of the production well 12.
Turning to FIG. 7, a schematic example depicts a polarimetric sensing array 100 for the optical fiber 28 that is coupled to the casing 24 of the production well 12. The optical fiber 28 includes a sensor string 102 of optical sensors (e.g., sensor 1, sensor 2, sensor n). The polarimetric sensing array 100 also includes an interrogation system 104 with a laser light source 106, a first polarization detector 108, and a second polarization detector 110. Additionally, the interrogation system 104 includes a mixer 112 that mixes a return optical signal from the sensor string 102 and an optical local oscillator light signal from the laser light source 106. The mixer 112 outputs a plurality of output signal portions with two or more different polarizations.
The mixing performed by the mixer 112 involves splitting the return optical signal from the sensor string 102 into return light signal portions having different polarization states. The return light signal portions are then combined with the optical local oscillator light signal with an appropriate polarization to output the signal portions with two or more different polarizations. These signal portions are provided at path 114 and path 116 to transmit to respective polarization detectors 108 and 110. The polarization detectors 108 and 110 may then detect corresponding polarization states of the signal portions. It may be appreciated that although the mixer 112 is illustrated as outputting two output signal portions, the mixer 112 may, in some circumstances, output more than two output signal portions.
Based on the signal portions detected by the first polarization detector 108 and the second polarization detector 110, a birefringence of each of the sensors in the sensor string 102 may be determined. As a result, an effect of the birefringence of the sensors themselves on the optical fiber 28 may be removed from measurements made by the individual sensors in the sensor string 102. For example, the interrogation system 104 may analyze the effects of polarization and birefringence in real time to measure the birefringence of each of the sensors in the sensor string 102 and the state of polarization of the light at each of the sensors. In this manner, a sensitivity of the sensors to polarization due to birefringence is determined. The sensitivity may then be subtracted from an actual measurement made by each of the sensors. Accordingly, a measurement of non-zero-birefringence optical sensors can be separated from the effect of polarization.
Further, each optical sensor in the sensor string 102 may be defined by two successive reflectors 120. That is, the optical fiber 28 between each pair of the reflectors 120 may provide a corresponding optical sensor of the sensor string 102. The length of each optical sensor is represented as L, which is also the length of the optical fiber 28 between the reflectors 120. While the length L may be the same for each of the sensors, it may be appreciated that the sensors are also contemplated to have differing lengths L. The reflectors 120 may be a fiber Bragg grating (FBG), which reflects light of particular wavelengths and transmits other wavelengths. Additionally, other types of reflectors may also be used.
Each of the sensors may change an optical path length between the reflectors 120 under an influence of a measurand (e.g., strength of the electromagnetic field 40, or strength of the acoustic signal 58). The measurand may be converted to strain on the optical fiber 28, which is measurable interferometrically using a variety of techniques. Additionally, the sensitivity of each sensor may be controlled by the length L of the optical fiber that is exposed to detect the strain.
Individual pulses of light, each with a pulse length equal to or less than double the length L between the reflectors 120, are transmitted into the optical fiber 28 from the laser light source 106. Upon reaching a sensor, a portion of the pulse of light is reflected as the return optical signal that is ultimately provided to the interrogation system 104. The return optical signal is mixed at the mixer 112 with the optical local oscillator light signal, and the mixer 112 outputs two signal portions with two different polarizations to the first polarization detector 108 and the second polarization detector 110. In the polarization detectors 108 and 110, the state of the polarization for the pulses of light transmitted into the optical fiber 28 is determined. By determining the state of the polarization, the strength of the electromagnetic field 40 and/or the acoustic signal 58 may be determined. In this manner, a location of the transmitters 38 or 56 relative to the optical fiber may be determined based on measurements corresponding to locations of each of the sensors.
It may be appreciated that the example described in FIG. 7, above, is one of several methods for measuring the effect of the electromagnetic fields 40 or the acoustic signals 58 on the light pulses within the optical fibers 28. Accordingly, other methods for measuring these effects are also contemplated to be within the scope of the claimed subject matter. For example, while FIG. 7 depicts a system for measuring reflected light pulses, in other circumstances, the optical fiber 28 may include a complete loop. Therefore, in place of measuring reflected light pulses, the interrogation system 104 may measure the light pulses as they complete the loop of the optical fiber 28.
Further, it may be appreciated that the interrogation system 104 may be positioned at a surface of the production well 12. Accordingly, the optical fiber 28 may run from the surface of the production well 12 to an end of the casing 24 within the production well 12. Additionally, in some circumstances, the interrogation system 104 may be positioned at some point within the production well 12. In such an example, the interrogation system 104 may relay data measured at the optical fiber 28 back to the surface of the production well 12 using a wireless telemetry system or any other available wireless communication system. Moreover, in other examples, the interrogation system 104 may communicate data with the surface using a wired transmission path from the interrogation system 104 disposed within the production well 12 to the surface of the production well 12.
While certain features of the subject matter have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. Particularly, though the subject matter has been described with examples involving SAGD wells, the techniques may be applied to any relative orientation between two wells. It is, therefore, to be understood that the appended claims are intended to cover any modifications and changes that fall within the true spirit of the claimed subject matter.

Claims

What is claimed is:

1. A method comprising:

drilling a new well in a geological formation having a previously drilled well using a bottom hole assembly (BHA) having a transmitter;

transmitting a signal while drilling using the transmitter of the BHA; and

measuring from the previously drilled well the signal from the transmitter received by at least one optical fiber disposed within the previously drilled well.

2. The method of claim 1, comprising determining a relative position of the new well to the previously drilled well using measurements of the signal.

3. The method of claim 2, wherein the relative position of the new well to the previously drilled well is determined based on a measurement of a polarization state of light within the at least one optical fiber.

4. The method of claim 1, wherein the transmitter transmits the signal, wherein the signal comprises an electromagnetic field.

5. The method of claim 1, wherein the transmitter transmits the signal, wherein the signal comprises an acoustic signal.

6. The method of claim 1, comprising measuring from the at least one optical fiber disposed within the previously drilled well an acoustic signal originating from acoustic noise associated with drilling the new well.

7. The method of claim 6, comprising monitoring drilling dynamics of the new well based on measurements of the acoustic signal.

8. The method of claim 1, wherein the previously drilled well comprises a production well and the new well comprises an injector well in a steam assisted gravity drainage (SAGD) well system.

9. The method of claim 1, wherein drilling the new well comprises drilling the new well such that the new well maintains an approximately constant distance from the previously drilled well.

10. A drilling system comprising:

a bottom hole assembly (BHA) having a transmitting device, the transmitting device configured to transmit a signal from the BHA while drilling a new well;

at least one optical fiber disposed within a previously drilled well and configured to interact with the signal transmitted from the transmitting device; and

a polarization detector coupled to the at least one optical fiber, wherein the polarization detector is configured to measure a polarization state of light within the at least one optical fiber.

11. The drilling system of claim 10, comprising a steerable system configured to adjusting a drilling trajectory of the BHA while drilling the new well based on measurements of the polarization state of the light within the at least one optical fiber.

12. The drilling system of claim 11, wherein the steerable system is configured to maintain a constant distance between the new well and the previously drilled well as the new well is drilled.

13. The drilling system of claim 10, wherein a measurement of the polarization state of the light indicates a distance between the new well and the previously drilled well.

14. The drilling system of claim 10, wherein the transmitting device transmits electromagnetic fields.

15. The drilling system of claim 10, wherein the transmitting device transmits acoustic signals.

16. The drilling system of claim 15, wherein the acoustic signals originate from drilling noise associated with drilling the new well, and wherein measurements of the polarity state of the light represent drilling dynamics in the new well.

17. A method of drilling a well comprising:

drilling a second horizontal well above a first horizontal well using a bottom hole assembly (BHA) having a first transmitting device;

transmitting a first signal from the first transmitting device while drilling the second horizontal well; and

measuring from an optical fiber within a first horizontal well the first signal from the first transmitting device.

18. The method of claim 17, comprising adjusting a trajectory of the BHA such that the second horizontal well will be drilled substantially parallel to the first horizontal well based on measurements of the first signal from the first transmitting device.

19. The method of claim 18, wherein the second horizontal well maintains a distance of approximately 5 meters above the first horizontal well.

20. The method of claim 17, comprising estimating a location of the first transmitting device in relation to the first horizontal well based on a change in polarization state of light within the optical fibers of the first horizontal well as the first transmitting device moves toward or away from the first horizontal well.

21. The method of claim 17, wherein the first transmitting device transmits acoustic signals or electromagnetic fields.

22. The method of claim 17, wherein the first horizontal well and the second horizontal well are steam assisted gravity drainage (SAGD) wells.

23. The method of claim 17, comprising transmitting a second signal from a second transmitting device, wherein the second signal is an acoustic signal, and the first signal from the first transmitting device is an electromagnetic field.

24. The method of claim 17, wherein the first transmitting device comprises drilling components for drilling the second horizontal well, and wherein the first signal comprises acoustic signals originating from drilling noise associated with drilling the second horizontal well.