Patent Application
20130188168
Hydrocarbon fluids, such as oil and natural gas, are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore is drilled, various well completion components may be installed to control and enhance the efficiency of producing the various fluids from the reservoir. However, the production of hydrocarbon fluids from the reservoir can result in dimensional changes of the formation. In some instances, the dimensional changes are due to compaction and subsidence. In other instances, the reservoir may experience thermal expansion, for example where heating (such as with steam) is used in enhanced oil recovery methods. In either case, dimensional changes can lead to fracturing of the hydrocarbon-bearing formations and surface deformations, both of which can affect the stability of surface installations.
Certain embodiments of the invention are described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying drawings illustrate only the various implementations described herein and are not meant to limit the scope of various technologies described herein. The drawings show and describe various embodiments of the current invention.
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element”. Further, the terms “couple”, “coupling”, “coupled”, “coupled together”, and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention.
Available techniques that can be used to monitor dimensional changes of a formation either do not provide for direct monitoring of dimensional changes of the formation itself, do not result in accurate measurements of dimensional changes, and/or cannot withstand the elevated formation temperatures that result when enhanced recovery techniques are employed. As examples, conventional surface surveying techniques (e.g., theodolite based or synthetic-aperture radar satellite techniques) can provide some indication of surface changes that may be a result of dimensional changes of a subterranean formation. However, observation of surface changes provides only an indirect means for monitoring dimensional changes of the formation itself. While known microseismic monitoring techniques may provide an indication of the location of fracturing and fault activation, these techniques also cannot provide a direct measurement of dimensional changes of the formation. Likewise, methods of measuring deformation of the well casing cannot provide a direct assessment of the dimensional changes of the formation. Active seismic monitoring can provide a general image of the reservoir, but lacks the accuracy desired for monitoring dimensional changes of the formation. Electrical monitoring techniques are not suitable for monitoring dimensional changes of the formation as they are unable to withstand the elevated temperatures reached by the reservoir when production is stimulated by heat.
Accordingly, various embodiments of the invention comprise methods and apparatus that directly monitor dimensional changes of a reservoir, such as compaction and/or swelling of the hydrocarbon-bearing formation. The methods and apparatus employ fiber optic measurement techniques to monitor dimensional changes within the formation and, thus, are able to withstand the harsh conditions present in the subterranean environment. In general, in various embodiments, a fiber optic cable assembly is lowered into a wellbore that penetrates a hydrocarbon-bearing formation of interest. The cable assembly has at least two reference points, one of which is attached or connected to the open wellbore wall (such as to the rock or other subterranean material) at a first reference point relative to the formation (e.g., above the formation) and the other of which is attached to the wellbore wall at a second reference point relative to the formation (e.g., below the formation) so that the cable assembly extends across the formation or portion of the formation of interest. Changes in the optical path length between the two reference points can then be measured from the surface using any of a variety of fiber optic monitoring techniques (as will be described in further detail below). These measurements provide a direct indication of dimensional changes within the formation of interest, including compaction and/or swelling.
In some embodiments, the temperature distribution or average temperature is also measured along the optical path between the two reference points using various fiber optic measurement techniques (as will be described in further detail below). The measurement of the changes in optical path length can then be corrected to compensate for temperature changes between the reference points. The corrected optical path length can be used to determine changes in distance between the optical assembly attachment locations on the wellbore wall on either side of the formation of interest and, thus, dimensional changes of the formation itself.
With reference now to
The attachment of the optical fiber 214 to the wall of the conduit 216 can be achieved in a variety of manners. For instance, the optical fiber 214 may be coated with a metallic coating which can then be attached to the wall of the conduit 216 by high temperature soldering. In the embodiment of
In other embodiments, the optical fiber 214 can be introduced within the conduit 216 using other techniques, such as by forming a metallic tube about the optical fiber 214 followed by seam-welding the metallic tube to enclose the optical fiber 214 therein. In some embodiments, the optical fiber 214 may be secured at the reference points 215, 217 along the conduit 216 using glass-metal seals or elastomeric compression joints, for example.
In various implementations of the optical fiber assembly 200, the optical fiber 214 is deployed within the conduit 216 so that it will remain under sufficient tension so that substantially no slack is present when the assembly 200 is placed in the wellbore 202. This manner of deployment of the optical fiber 214 within the control line 216 is generally referred to as “understuffing.” Alternatively, the optical fiber 214 can be deployed within the conduit 216 with a controlled length of excess optical fiber 214 that has been selected so that the optical fiber 214 can withstand and operate without damage over the range of strain to which it will be exposed in the wellbore 202. This manner of deployment within the control line 216 is generally referred to as “overstuffing.” Regardless of whether the optical fiber 214 is understuffed or overstuffed, the optical fiber 214 is deployed in the control line 216 so that a desired length of fiber 214 relative to the length of the control line 216 is maintained.
In alternative implementations of the monitoring techniques and apparatus described herein, the optical cable assembly 200 includes two separate sections that together extend across the formation 206 when the assembly 200 is deployed in the wellbore 202. For instance, with reference to
Returning to the exemplary embodiment of
Generally, during installation, the cable assembly 200 is attached to the retention devices 230, 232 so that the assembly 200 is initially placed under tension. In this manner, the optical cable assembly 200 can detect both a reduction (compaction) and an increase (swelling) of the dimensions of the formation of interest 200. In various embodiments, tension may be achieved by first securing the cable assembly 200 to a first one of the attachment points (e.g., the lower attachment point 212), applying tension to the cable assembly 200, and then securing the cable assembly 200 to the second one of the attachment points (e.g., the upper attachment point 210). In installations where more than two attachment points are used, this process of securing to an attachment point and applying tension can be repeated.
In some embodiments, the attachment points 210, 212 can be implemented using releasable retention devices 230, 232. For instance, the retention devices 230, 232 can include a releasable engagement mechanism 231, 233 (e.g., a latch or releasable lock) that can selectively engage and release the cable assembly 200. The releasable latch or lock 231, 233 can be controlled from either a local power and control source or a remote power and control source that is located, for instance, at the surface 204. The power and control source can be implemented in any of a variety of manners, such as mechanical, electrical, hydraulic, pneumatic, optical, etc. In other embodiments, the releasable engagement mechanism(s) 231, 233 can be configured to respond to control signals in a manner that results in adjustment of the tension applied to the optical cable assembly 200. In this manner, long-term variations in the strain experienced by the optical cable assembly 200 (and thus the strain applied to the optical fiber 214 within the assembly 200) can be limited to a value that is within the safe (reliable) operating range of the optical fiber 214.
In yet other embodiments, rather than using retention devices 230, 232 at selected locations, the entire optical cable assembly 200 may be secured to the wellbore wall 208 using cement. In such embodiments, to ensure that the optical cable assembly 200 is placed under an initial, or baseline, tension, a lower section of the optical cable assembly 200 can be cemented in place first and the cement allowed to cure. Tension can then be applied to the cable assembly 200 while further cement is applied to secure the entire cable assembly 200 along the wellbore wall 208. If desired, varying strengths of cement may be applied to allow for compaction of certain regions of the formation 206 while retaining a firm attachment to the wellbore wall 208 at other locations.
Regardless of the manner of attachment of the optical cable assembly 200 along the wellbore wall 208 to the attachment points 210, 212 above and below the formation of interest 206, in some embodiments, the optical cable assembly 200 can be used to directly monitor dimensional changes within the formation 206 via surface instrumentation 224 that measures changes in optical path length of the section of the fiber 214 between the reference points 215, 217. The surface instrumentation 224 can be configured to implement any of a variety of different optical measurement techniques to monitor optical path length changes, including measuring the strain incident on the optical fiber 214 between reference points 215 and 217 or the optical path imbalance. In addition, the surface instrumentation 224 can implement optical measurement techniques that measure the temperature profile between the reference points 215, 217 so that the measured optical path length changes can be corrected to compensate for variations in temperature between the reference points 215, 217.
For instance, as shown in
In various implementations, the surface instrumentation system 224 is configured to measure optical path length changes by measuring the strain profile of the optical fiber 214 between the two reference points 215, 217. In exemplary embodiments, the surface instrumentation 224 can be configured to implement Brillouin measurement techniques, such as Brillouin optical time domain reflectrometry (BOTDR) or Brillouin optical time domain analysis (BOTDA) techniques, to measure the strain profile. Changes in the elongation of the fiber 214 (i.e., changes in the optical path length) due to the incident strain can be deduced by integrating the measured strain profile of the fiber 214 between the known reference points 215, 217. When BOTDR is used, the surface instrumentation 224 measures the peak of the Brillouin spontaneous emission. In such an embodiment, the intensity of the spontaneous emission or process linewidth also can be measured by the instrumentation 224 to provide information about the temperature profile between the reference points 215, 217. In embodiments in which BOTDA is used, the surface instrumentation 224 measures the peak frequency of the Brillouin gain spectrum. However, because the Brillouin frequency is strain and temperature dependent, the surface instrumentation 224 is configured to also make an independent measurement of temperature in order to correct the strain measurement for the effects of temperature. The instrumentation 224 can obtain temperature information by measuring the intensity of the Brillouin spontaneous emission using BOTDR. Alternatively, temperature profile information may be derived from other known optical measurement techniques, such as by measuring spontaneous Raman scattering as an example. For the Brillouin measurement techniques, the optical fiber 214 used in the cable assembly 200 can be a single-mode optical fiber, although other types of optical fiber, such as multi-mode fiber may also be employed.
Another optical measurement technique that can be implemented by instrumentation 224 to measure the strain incident along the length of the optical fiber 214 that extends between the reference points 215, 217 involves the use of one or more fiber Bragg gratings (FBGs), such as an FBG 234, which is formed in the fiber 214 between the reference points 215, 217 (see
FBGs are sensitive to temperature, primarily through the thermo-optic effect. Consequently, the strain measurement obtained by instrumentation 224 also will be temperature-sensitive. Embodiments that employ one or more FBGs to measure the strain profile between the reference points 215, 217 can correct for the temperature sensitivity by configuring the surface instrumentation 224 to also make an independent measurement of the temperature profile between the reference points 215, 217. Again, this measurement may be achieved using Raman distributed temperature sensing, as an example.
Alternatively, the combination of Brillouin frequency measurement and the FBG measurement can be used to correct the strain measurement, because the matrix relating the sensitivities of FBG wavelength and Brillouin frequency to temperature and strain is reasonably well conditioned. In embodiments employing this alternative temperature correction approach, the FBG 234 typically would measure the average strain distribution over the length of the optical fiber 214 between the two reference points 215, 217, but are only locally sensitive to temperature at the location of the FBG 234. In contrast, the Brillouin measurement provides a distribution of frequency that relates to the distribution of both temperature and strain between the reference points 215, 217. The strain can be regarded as uniform over the entire length of the fiber 214 between the reference points 215, 217. Even so, the distributed nature of the Brillouin measurement can provide a compensating measurement local to the FBG 234.
Other embodiments of the dimensional change monitoring techniques and apparatus described herein may implement yet other optical techniques to measure the strain of the optical fiber 214 (and, hence, the change in optical path length between reference points 215, 217). For instance, as shown in
In such an illustrative embodiment, reflectors 231, 233, 235 can be incorporated in to the optical fiber 214 in the form of fiber Bragg gratings that are used purely as reflectors (as opposed to strain sensors where shifts in reflected wavelengths are indicative of strain, as described previously). Other types of suitable reflectors 231, 233, 235 include reflective splices along the length of the fiber 214 at reference points 215, 217, 237 or the incorporation of power splitters at reference points 215, 217, 237 that tap off a portion of the light that launched into and is propagating along the length of the fiber 214. In the latter case, the tap ports for the power splitters incorporate reflectors 231, 233, 235 (e.g., mirrors) to return the light to the launch end 238 of the optical fiber 214.
In embodiments that employ reflectors 231, 233, 235, the optical fiber 214 conceptually can be viewed as being divided into sensitive zones, where each zone is located between a pair of reflectors. The reflectors 231, 233, 235 are located at the reference points 215, 217, 237 where the cable assembly 200 is attached the wall 208 of the wellbore 202, and the zones between reflectors 231, 233, 235 effectively form sensing elements.
With reference to
After separation of forward and backward-traveling light (e.g., by the circulator 246), the returned light is directed to the receiver 248, which converts the optical pulses into electrical pulses. The electrical pulses are then received by a discriminator 250 which converts the analog electrical pulses into digital pulses with a reliable timing relationship between a measure of the arrival time of the analog pulse (e.g., the 50% point on one of its edges or its first moment) and an edge of the digital pulse. The output of the discriminator 250 is used to latch the output of the counter 244 and also to cause a second circuit 252 (i.e., a fine interpolation time-to-digital converter) to provide a digital output 254 dependent on the delay between the latest clock pulse and the output of the discriminator 250. The coarse and the fine delay measuring circuits 244, 252 together provide a high-resolution and wide dynamic range measurement of the propagation delay between the triggering of the optical source 240 and each returned optical signal at the output 254. This arrangement can be configured to measure the reflected light returned from each reflector 231, 233, 235 individually. Alternatively, the arrangement can be configured to latch the output for each reflector 231, 233, 235 and continue to acquire the timing associated with further reflectors. Using a readily available time-to-digital converter 252, a single-shot resolution of 10-20 picoseconds is achievable (corresponding to a round-trip transit time resolution of 1-2 millimetres). Accuracy of the measurements can be further enhanced by averaging successive readings obtained from a particular reflector 231, 233, 235.
The transit time data at output 254 for each reflector 231, 233, 235 can then be subtracted between successive reflectors to determine the optical path length between each pair. Because the optical path length is dependent on both strain and temperature, embodiments of the measurement technique apply a temperature-based correction to the strain measurement to compensate for the effects of temperature. The correction may be achieved by configuring the surface instrumentation 224 to include circuitry 251 that is configured to make any one of the temperature measurements described above.
An alternative arrangement of surface instrumentation 224 for measuring the time of flight of reflected pulses is illustrated in
Returning now to
The second lower anchor or attachment point 212 below the formation of interest supports the lower section 222 of the assembly 200. The lower section 222 includes a second conduit 264. The second conduit 264 has a diameter that is different (e.g., smaller) than the diameter of the first conduit 216 so that the first conduit 216 can slide telescopically either inside or outside of the second conduit 264. The reflector 226 (e.g., a mirror, corner cube, etc.) is fixed inside of the second conduit 264 at the reference point 217. This reflector 226 reflects light arriving from above from the upper section 228. The optical fiber 214 within the first conduit 216 can be terminated with a lens arrangement 266 that collimates the light (as illustrated by the dotted lines) emerging from remote end 268 of the optical fiber 214 to direct it to the reflector 226. The lens arrangement 266 also collects and re-launches into the optical fiber 214 light that is reflected from the reflector 226.
In this embodiment, light that is launched from the surface instrumentation 224 propagates to the remote end 268 of the optical fiber 214. A portion of the light that arrives at the remote end 268 of the optical fiber 214 is reflected back to the launch end 238 of the optical fiber 214. Another portion of the launched light emerges from the remote end 268 and is incident on the reflector 266 in the second conduit 264. The reflector 266 reflects the light back to the optical fiber 214 where it propagates to the launch end 238 for detection by instrumentation system 224.
A dimensional change in the formation 206 shown in
The path imbalance measurement itself is not temperature sensitive and, thus, does not require temperature compensation. However, temperature correction of the measurement may still be implemented to compensate for the expansion effects (and changes in the refractive index) in the length of the optical fiber 214 that extends between the upper attachment point 210 and the remote end 264 of the fiber 214. Again, a measurement of the temperature profile along this length of the optical fiber 214 may be obtained by employing any of the distributed temperature measurement techniques described above.
As discussed above, the various measurements of optical path length benefit from temperature compensation to correct the measured parameter to cancel the effect of temperature changes between the reference points. In the case of the strained fiber techniques described above, the purpose of the correction is to separate the effects of temperature from those of strain, since the parameters that are measured are generally dependent on both temperature and strain. In the case of the suspended fiber arrangement shown in
The temperature-corrected optical path length change measurement is a direct indicator of a change in the distance between the reference points 215, 217. When these reference points 215, 217 are attached to the wellbore wall 208 at attachment points on either side of the formation (or portion of the formation) of interest 206, the optical path length change measurement is a direct indicator of a dimensional change (e.g., thickness) within the formation 206.
In various embodiments, the surface instrumentation 224 can include all or part of the processing subsystem 253 that corrects the optical path length measurements and converts the corrected optical path length measurements to dimensional changes using known relationships between the measured parameter (e.g., Brillouin frequency, flight time, path imbalance) and distance. In other embodiments, the processing subsystem 253 may be at a location remote from the wellbore 202. In other embodiments, the optical path length change may be converted to dimensional changes of the formation 206 by an operator or user having access to the measurements obtained by the surface instrumentation system 224.
In some embodiments, the systems and techniques described herein may be employed in conjunction with an intelligent completion system disposed within a well that penetrates a hydrocarbon-bearing earth formation. Portions of the intelligent completion system may be disposed within cased portions of the well, while other portions of the system may be in the uncased, or open hole, portion of the well. The intelligent completion system may comprise one or more of various components or subsystems, which include without limitation: casing, tubing, control lines (electric, fiber optic, or hydraulic), packers (mechanical, sell or chemical), flow control valves, sensors, in flow control devices, hole liners, safety valves, plugs or inline valves, inductive couplers, electric wet connects, hydraulic wet connects, wireless telemetry hubs and modules, and downhole power generating systems. Portions of the systems that are disposed within the well may communicate with systems or sub-systems that are located at the surface. The surface systems or sub-systems in turn may communicate with other surface systems, such as systems that are at locations remote from the well.
It should be understood that embodiments of the invention are not limited to monitoring dimensional changes of subterranean, hydrocarbon-producing formations as shown in the illustrative examples. For instance, the fiber optic monitoring systems and techniques described herein can also be employed to monitor dimensional changes of other types of geological features (e.g., faults) which may be located either above or below the earth surface. It should also be understood that when used to monitor dimensional changes within hydrocarbon-producing formations, embodiments of the invention are not limited to the well structures shown in the illustrative examples. Cased, uncased, open hole, gravel packed, deviated, horizontal, multi-lateral, deep sea or terrestrial surface injection and/or production wells (among others) may incorporate a fiber optic formation dimension monitoring system as described. In many applications, the measurements of the dimensional changes of the hydrocarbon-producing formation may provide useful information that may be used to monitor and assure the stability of surface installations above the reservoir. For instance, the measurements may provide an indication of the onset of heave or subsidence that may affect the safety of personnel and equipment in the vicinity of the well. This information then can be used to take proactive measures to prevent damage, injury, or threats to the stability of the installation. As examples, reservoirs can suffer from subsidence after sustained production over an extended time and from water injected into the formation that dissolves the chalk (or other material) forming the reservoir. In the case of steam-assisted oil recover, the heating of the reservoir can lead to expansion and, thus, to heave at the surface. In addition, the information gained from the measurements can be used to validate and improve models of reservoir drainage, including geomechanical models that facilitate optimization of the extraction from the reservoir.
While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations there from. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.
