Abstract:
A system based on a series of data accumulation hubs, connected together by high speed communication backbone for routing a limited number of data and power cables is suggested. Each hub is connected to arrays of sensor pods which contain the actual sensor elements and minimal, if any, interface electronics. Preferably, as many as 20 sensor pods can be connected to each single hub element wherein a system including five hub elements with 20 sensor pods each would comprise a 100 element array. The data from the individual sensors are accumulated in the hubs, buffered, and conditioned for transmission to the surface data acquisition system through the high speed metal backbone comprising multiple paths of transmission for redundancy in the event of failure. Provisions are made within each of the hubs so that if a hydrostatic leak were to occur, the fault can be isolated and the remainder of the system will function as designed. A power delivery network is also preferably encased within the backbone along with the high speed data link.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention generally relates to a method and an apparatus for detecting and monitoring various conditions (e.g. seismic, pressure, and temperature signals) in and around a borehole. More particularly, the invention relates to a sensor array suitable for long-term placement inside a well, thereby permitting diverse measurements concerning the state of the well, flows inside the well, and the evolution of the reservoir over time. 
     2. Description of the Related Art 
     During the production of hydrocarbons from an underground reservoir or formation, it is important to determine the development and behavior of the reservoir and to foresee changes which will affect the reservoir. Various methods for determining and measuring downhole parameters for forecasting the behavior of the reservoir are well known in the art. 
     One method includes placing one or more sensors downhole adjacent the reservoir and recording seismic signals generated from a source often located at the surface. Hydrophones, geophones, and accelerometers are three typical types of sensors used for recording such seismic signals. Hydrophones respond to pressure changes in a fluid excited by seismic waves, and consequently must be in contact with the fluid to function. Hydrophones are non-directional and respond only to the compressional component of the seismic wave. They can be used to indirectly measure the shear wave component of a seismic wave when the shear component is converted to a compressional wave (e.g. at formation interfaces or at the wellbore-formation interface). Geophones measure both compressional and shear waves directly They include particle velocity detectors and typically provide three-component velocity measurement. Accelerometers also measure both compression and shear waves directly, but instead of detecting particle velocities, accelerometers detect accelerations, and hence have increased sensitivity at higher frequencies. Accelerometers are presently available with three-axis acceleration measurements. Both geophones and accelerometers can be used to determine the direction of arrival of the seismic wave. Any of the above devices or a combination thereof can be used to measure seismic signals within a borehole. Additional sensors that may prove beneficial to reservoir engineers include, but are not limited to, temperature sensors, pressure transducers, and position monitors (gyroscopes). Any or all of these sensors may be deployed concurrently with seismic sensors to help the engineer determine reservoir status. 
     In the past, wireline tools have been used to deploy well logging or vertical seismic sensors to profile reservoirs from within the bore of a well. Wireline sondes can contain a large assortment of sensors enabling various parameters to be measured, including acoustic noise, natural radioactivity, temperature, pressure, etc. The sensors may be positioned inside the production tubing for carrying out localized measurements of the nearby annulus or for monitoring fluid flowing through the production tubing. Although effective, wireline sondes are not considered a long term solution. Often a more permanent method for equipping wells with sensors is desired. Permanent sensor installations grant the reservoir engineer the ability to record time-lapse measurements over periods spanning days, months, and years. Such time-deferred measurements allow reservoir operators a more detailed picture of the amount of reserves remaining and the rate at which they are diminishing. 
     Additionally, many sensors, including accelerometers and geophones, must be mechanically coupled to the well formation in order to be effective. While wireline sensors of this type are currently in existence, they are often bulky and require special actuators to couple the sensor to the casing or formation wall and are not considered permanent. Permanent sensor arrays also provide the reservoir engineer with the ability to record measurements over a broader region and for longer periods of time. 
     Most of the cost of a typical seismic survey lies within the data acquisition methods currently performed upon temporary arrays of surface sources and receivers. Long-term emplacement of the receivers has the potential of significantly lowering data acquisition and deployment costs. There are two major benefits of long-term emplacement of sensors, first, repeatability is improved, and second, by positioning the receivers closer to the reservoir, noise is reduced and vertical resolution of the seismic information is improved. Further, from an operational standpoint, it is preferred that receivers be placed in the field early to provide the capability of repeating 3-D seismic surveys at time intervals more dependent on reservoir management requirements than on data acquisition constraints. By obtaining a sequence of records distributed over a long period of time, it becomes possible to monitor the movement of fluid in the reservoirs, and to thereby obtain information needed to improve the volume of recovered hydrocarbons and the efficiency with which they are recovered. For whatever the reason long-term emplacement is desired, it is of utmost importance that emplaced sensors move as little as possible throughout their lifetime. Movement in long-term sensors can disrupt the credibility of data collected over long periods of time. 
     A “permanent” method that has been previously used involves the attaching of sensors to the exterior of the well casing as it is installed. Following installation, the annulus around the casing is then cemented such that when the cement sets, the sensors are permanently and mechanically coupled to the casing and formation. One major drawback to a system of this type, is that there is considerable chance for a failure during the installation process, a failure that will, for the most part, not be detectable until after the cementing process is complete. If a system becomes inoperable following cementing, it becomes prohibitively expensive and difficult to repair the system and it is left in place, in an inoperable condition. Another limitation of this system is that it must be installed during the well construction process, before completion. Such a system can not be added to a well at a later date if desired. 
     An apparatus for a permanent sensor array has been presented in U.S. patent application Ser. No. 09/260,746 Method for Permanent Emplacement of Sensors Inside Casing filed Mar. 1, 1999 by John W. Minear hereby incorporated herein by reference. Minear presents a system whereby an array of permanent sensor devices are installed within well casing by having them mounted about the outer profile of a string of coiled tubing installed therein. In one instance, the sensors of Minear are mounted upon spring loaded carriers that are compressed during installation and held into place following installation by the stored energy of the springs loaded carriers. This arrangement allows for the sensors to be mechanically coupled to the casing, with little chance of positional changes over long periods of time. The main advantage that such a system provides is the ability to have a permanent sensor array that can be retrieved in the event of a system failure. Minear also provides a solution whereby the sensors of the array are connected to one another and the surface by a durable and flexible cable. The cable of Minear is as durable and crush resistant as metal conduit, but flexible to allow effective emplacement of sensors against the casing wall. 
     The only potential drawback to the system as proposed by Minear is that there may be a significant risk of damage to the sensor pods during array installation. As sensors are engaged through the casing, they are held against the casing wall by the spring loaded carriers and are essentially “dragged” to their final destination. During such an operation, it is possible that one or more of the sensor devices will become damaged and inoperative. Unless expensive fault isolators are installed in conjunction with each sensor, a damaged sensor on a typical array can require the retrieval of the entire system for repairs. 
     Even after installation is successfully completed, there remains a chance for failures to occur in the many months following the original installation. If the entire sensor array must be removed from the wellbore for repairs, long term data analysis can no longer be performed with precision as the position of each sensor will have changed relative to the formation, making most extended time lapsed “before” and “after” data comparisons invalid. For this reason, an arrangement and method that ensures the effective operation of a “permanent” sensor array for many years following installation is of utmost importance to reservoir engineers. 
     A reliable permanent sensor array system has long been identified as highly desirable by reservoir engineers. The system could be compatible with a variety of existing standard surface seismic sources in order to provide high quality seismic measurements. By emplacing the sensors permanently in the well, the variances that result from repositioning the sensors between repeat surveys of a long term monitoring project can be eliminated. The sensor array must be reliable as it may need to be in place for as many as 10 years to provide the necessary surveys and must be capable of surviving hostile environments, including elevated temperatures, pressures, and corrosive wellbore fluids. Finally, the permanent sensor array must be economical to produce and deploy. 
     Current means of communication with the surface for sensor arrays are either digital or analog. Analog communication typically requires a twisted pair of wires to be run to the surface for each of the deployed sensors. For arrays with large amounts of sensors, this communication can require a very large umbilical cable to be run from the surface to the sensors. For example, an array of 100 sensor pods containing 3 accelerometers (one for each axis) would require a 600 wire umbilical cable. For most installations, this is too large to be feasible. Additionally, the accuracy of deployed sensors in such a system can be reduced as a result of cable attenuation and crosstalk effects. Environmental tolerance is also generally poor due to variation in the cable characteristics after prolonged exposure to elevated temperature and pressure. 
     Alternatively, a digital communication system can be deployed in place of the analog communication system to offer a dramatic reduction in required cable size. For the example above, a comparable digital array of sensors could be arranged such that all 100 pods and all 300 sensors could communicate to the surface with one wire or a fiber optic line. A major drawback of the digital method described above is that failure of one sensor pod can destroy the entire communication link to all others. 
     The present invention overcomes these deficiencies of the prior art. 
     BRIEF SUMMARY OF THE INVENTION 
     The deficiencies of the prior art can be resolved using a system that is based on a series of data accumulation hubs, connected together by high speed communication backbone for routing data and power signals. Each hub is then connected to an individual array of sensor pods which contain the actual sensor elements and minimal interface electronics. Upper and lower strings of sensor pods are connected to each hub by flexible elastomeric cable to ease the emplacement of the sensors against the casing. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a detailed description of a preferred embodiment of the invention, reference will now be made to the accompanying drawings wherein: 
     FIG. 1 is a simplified schematic of a well; 
     FIG. 2 is a close up view of a length of production tubing showing a schematic representation of a permanent sensor array in accordance with a preferred embodiment of the present invention; 
     FIG. 3 is a zoomed out view of the sensor array of FIG. 2 to schematically show grouping schemes; and 
     FIG. 4 is a block diagram of an exemplary hub embodiment. 
    
    
     While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Referring initially to FIG. 1, there is shown a simplified depiction of a well  100 . Well  100  has an outer casing  102  extending from a wellhead  104  at the surface  106  through a large diameter borehole  108  to a certain depth  110 . Outer casing  102  is cemented within borehole  108 . An inner casing  112  is supported at wellhead  104  and extends through outer casing  102  and a smaller diameter borehole  114  to the bottom  116  of the well  100 . Inner casing  112  passes through one or more production zones  118 A,  118 B. Inner casing  112  forms an annulus  120  with outer casing  102  and an annulus  122  with borehole  114 . Annulus  120  and annulus  122  are filled with cement  124 . A production tubing string  126  is then supported at wellhead  104  and extends down the bore  128  of inner casing  112 . The hydrocarbons from the lowest production zone  118 B flow up the flow bore  136  of production tubing  126  to the wellhead  104  at the surface  106 , while the hydrocarbons from the other production zone  118 A may be comingled with the flow from zone  118 B or may flow up the annulus between inner casing  112  and tubing  126 . A christmas tree  138  is disposed on wellhead  104  and is fitted with valves to control flow through tubing  126  and the annulus around tubing  126 . 
     Referring now to FIG. 2, a drawing of a wellbore including a schematic drawing of a permanent downhole sensor array system is shown. Wellbore  200  is drilled within a formation  202  and includes a casing  204  and a tubing string  206  engaged within to form an annulus  208 . Mounted about tubing string  206  is a permanent sensor array  210 . Sensor array  210  shown in FIG. 2 comprises a network of data hubs  212 , each with an upper branch  214  and a lower branch  216  of sensor pods  218  mounted upon data cables  222 . A conduit  220  connects hubs  212  together and contains communication and power distribution wires. 
     Sensor array  210  is preferably deployed by attaching it about the outer profile of tubing string  206  while it is engaged within casing  204 . Array  210  is positioned upon tubing string  206  such that sensor pods  218  will correspond to desired points of investigation once tubing  206  is fully deployed within wellbore  200 . Sensor array  210  is based on a system of electronic hubs  212  that are connected to each other and to the surface by means of conduit  220 . Conduit  220  is preferably a rigid metal tubular structure and preferably houses both a high speed communications network and a power distribution backbone. 
     Preferably, hubs  212  contain all or most electronic devices necessary for the array to communicate with and distribute power from the surface equipment. By locating all electronic communication and power devices for array  210  within hubs  212 , the complexity, size, weight, and expense of sensor pods  218  can be minimized. To maintain reliability, hubs  212  may be properly sealed to prevent drilling fluid leakage and be manufactured of a durable material that is capable of surviving the extreme wear, heat and impact situations that are commonly experienced in downhole environments, In the preferred embodiment, hubs  212  and conduit  220  are rigidly attached to the outer surfaces of tubing  206  by any one or more of an assortment of methods including but not limited to adhesives, straps, clamps or welds. 
     Connected to hubs  212  by means of a cable apparatus  222  are upper branches  214  and lower branches  216  of sensor pods  218 . Sensor pods can contain any number or configuration of sensors to detect and report back well and reservoir conditions. Although no specific apparatus or method is required, it is preferred that pods  218  be held firmly in place by means of a spring loaded engagement device (not shown) to maintain secure contact between pods  218  and the surface of casing  204 . Additionally, it is preferred that sensor pods  218  be mounted upon a cable assembly  222  that is flexible to facilitate their secure emplacement against casing  204  or formation  200 . If cable apparatus  222  were inflexible, emplacement method would require an increased biasing capability in order to properly secure sensor pod  212  against wall of casing  204  or formation  202 . Acceptable embodiments for cable assembly  222  and spring loaded engagement device are presented in the above referenced Minear application. 
     Sensor information is transmitted from pods  218  to the reservoir engineer at the surface by first routing it through data collection hubs  212 . Communication between sensor pod  218  and hub  212  can either be digital or analog, and can be accomplished through metallic wires, optical fibers, or any other acceptable form of transmission. In a preferred embodiment, each sensor within a pod  218  communicates to its hub  212  though a twisted wire pair and utilizes analog communication. For example, a sensor pod containing three accelerometers (one for each axis of investigation) will have a total of 6 wires communicating with its hub. For a sensor array  210  wherein each branch  214  or  216  contains 5 sensor pods, as many as 30 wires may need to be contained within each cable assembly  222 . Analog communication is preferred for this communication link because it does not require any additional electronics to be located within sensor pods  218 . Because the length and number of wires within each cable assembly  222  is relatively small, the signal loss and required cable diameter is low enough to allow communication between sensor pods  218  and hub  212  at a level of reliability and quality not commonly associated with downhole analog signals. 
     In contrast, digital communication is preferred for the link from hub  212  to the surface because of its reliability over long lengths and potential for high speed data transmission. Each hub  212  receives data from sensor pods  218  of upper  214  and lower  216  branches and encodes the data for communication with the surface. Additionally, hubs  212  may also include sensors that are not contained in sensor pods  218 . The types of sensors that are located within data hubs  212  typically either require complex electronics to operate, do not need frequent measurements, or are too expensive to place in every sensor pod  218 . Once data is collected in hubs  212 , it is sent to the surface by a high speed communication link contained within conduit  220  where reservoir engineers are able to extrapolate information that they need. 
     Additionally, it is preferred, but not required, that every hub  212  have a fault isolator installed so that in the event of a failure of a hub  212 , the remaining hubs on the circuit are not disabled. An example of such a fault isolator is a pressure fuse that, when crushed, electrically isolates the network  220  from the hub  212 , thereby preventing a failure of the hub from shorting out the network while preserving the connection to all the other remaining hubs. Because fault isolators of this type are expensive, it was not practical before to place them in conjunction with every sensor of prior art designs, but in conjunction with the hub design, they are more economically feasible. 
     FIG. 3 demonstrates an arrangement for a sensor array  211  in accordance with a preferred embodiment of the present invention. In this figure, four hubs,  212 A,  212 B,  212 C, and  212 D, are shown. Each hub contains a corresponding upper branch  214 A,  214 B,  214 C, and  214 D, of sensor pods  218 , and a corresponding lower branch,  216 A,  216 B,  216 C, and  216 D. The letter designations, A, B, C, and D, refer to a grouping that corresponds to a pair of twisted wires (not shown) contained within conduit  220 . The goal of array  211  is to increase system redundancy so that well resolution is reduced but not completely lost in the event of a component failure. Array  211  divides downhole sensors into four distinct communication systems but alternate grouping schemes can be used. For example in the four group arrangement, hubs  212 B,  212 C, and  212 D and their corresponding sensor pods  218  will function as normal if the A transmission twisted wire pair becomes shorted or damaged, and vice versa. Only sensor pods  218  attached to upper  214 A and lower  216 A branches of hubs  212 A that are serviced by communications line A are affected. Using this arrangement, only every fourth hub  212  in array  211  will be connected to a common twisted pair communications wire. This interleaving arrangement reduces the probability of losing all sensors in an entire section of the well. To minimize system cost and space requirements, all twisted wire pairs are preferably contained within a single conduit  220 . Array  210  of long-term sensor pods  218 , disposed on umbilical cable  220 , is preferably disposed on production tubing  206  as tubing  206  is assembled and lowered into the bore of inner casing  204 . Sensors  218  are preferably attached to the outside of the tubing  206  at specified depth intervals and may extend from the lower end of tubing  206  to the surface. A consideration in placing the arrays  210 ,  211  of sensors  218  is in protecting the sensors  218  and the telemetry path from damage during the emplacement operation. Umbilical cable  220  is preferably capable of withstanding both abrasion and crushing as the pipe is passed downwardly through the casing  204 . It should be appreciated that although the array  210  is shown disposed upon tubing  206 , array  210  may also be disposed on inner casing  204 . 
     In an exemplary implementation, a monitoring well could have 10 sensors spaced about 50 feet apart in each branch, so that a given hub carries the sensor information for a 1000 ft segment of the well. Each backbone cable in conduit  220  may support up to 5 such hubs. If 4 backbone cables are provided in conduit  220 , the hubs are preferably spaced 4000 ft apart, so that the 1000 ft segments for a given backbone cable are interleaved with those for other backbone cables. 
     FIG. 4 shows an exemplary embodiment of hub  212 . An analog-to-digital converter (ADC)  402  couples to the sensors on upper branch  214  and lower branch  216  and digitally samples their analog signals. A digital signal processor (DSP) or application specific integrated circuit (ASIC)  404  takes the digital samples, applies filtering or processing if desired, then communicates them to the surface using standard digital communications techniques such as, e.g., scrambling, error correction coding, interleaving, amplitude/phase modulation, orthogonal signaling, and pulse shaping. The communications signal from the DSP  404  is preferably confined to a frequency band assigned to hub  212 . This allows network  220  to employ frequency division multiplexing to concurrently carry communications signals from multiple hubs. Further, this allows power to be provided as a DC signal or a low-frequency signal over the network  220  without interfering with the hub communication signals. Still further, this allows the frequency range corresponding to a failed/failing hub to be filtered out at the surface, thereby avoiding impairment of communications with other hubs. 
     A line driver and amplifier block  406  is provided to buffer the signals to and from the DSP  404 . This improves the signal to noise ratio of the signals by avoiding distortion effects from line loading. All the signals to and from the network  220  pass through a fault isolator  408 , including a power signal to the power supply  410 . The power supply  410  conditions and regulates power for the other hub components, and preferably also for the sensors on branches  214  and  216 . 
     With multiple backbone cables in conduit  220 , the disclosed architecture supports interleaved sensor coverage segments so that as hub failures occur, the system may advantageously experience a graceful degradation rather than complete failure. Further, the system advantageously supports the use of a few, hardened hubs that, because of the small number, can have expensive redundancy features incorporated into them. These hubs are shared by a larger number of inexpensive, lightweight sensors that individually cause an insignificant degradation if they fail. It is expected that the overall system will cost less for a given level of reliability and performance than competing systems. 
     Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, it is noted that the disclosed system could be employed on both coiled tubing and threaded tubing. It is intended that the following claims be interpreted to embrace all such variations and modifications.