text:
An apparatus and a method for controlling oilfield production to improve efficiency includes a remote sensing unit that is placed within a subsurface formation, an antenna structure for communicating with the remote sensing unit, a casing joint having nonconductive "windows" for allowing a internally located antenna to communicate with the remote sensing unit, and a system for obtaining subsurface formation data and for producing the formation data to a central location for subsequent analysis. The remote sensing unit is placed sufficiently far from the wellbore to reduce or eliminate effects that the wellbore might have on formation data samples taken by the remote sensing unit. The remote sensing unit is an active device with the capability of responding to control commands by determining certain subsurface formation characteristics such as pressure or temperature, and transmitting corresponding data values to a wellbore tool. Some embodiments of the remote sensing unit include a battery within its power supply. Other embodiments include a capacitor for storing charge. In order for a communication link to be established with the remote sensing unit through a wireline tool in a cased well, a casing joint includes at least one electromagnetic window that is formed of a non-conductive material that will allow electromagnetic signals to pass through it. In the preferred embodiment, the electromagnetic windows are formed to substantially circumscribe the casing joint to render it largely rotationally invariant. The electromagnetic windows are formed of any rigid and durable non-conductive material including, by way of example, either ceramics or fiberglass.
1. A casing joint for a downhole data acquisition system, comprising:
a conductive tubular for providing structural integrity with at least one opening extending through the tubular; and
at least one window made of a non-conductive material and having the same dimension as said opening wherein the window is fitted within said opening to allow electromagnetic signals to pass through the casing joint.
2. The casing joint of
3. The casing joint of
4. The casing joint of
5. The casing joint of
6. The casing joint of
7. The casing joint of
8. A casing positionable in a wellbore penetrating a subsurface formation, comprising:
a plurality of tubular casing joints having an outer surface adapted to line the wellbore wherein at least one of the casing joints is of a type recited in
9. The casing of
10. The casing of
11. The casing of
12. The casing of
13. A method of communicating between a wellbore and a subterranean formation, comprising:
operatively connecting a plurality of casing joints to form a casing wherein at least one of the casing joints is of a type recited in
positioning the casing in the wellbore to line the wellbore; and
passing a signal through the non-conductive portion of at least one casing joint.
14. The method of
This is a divisional of U.S. patent application Ser. No. 09/394/831 filed Sep. 13, 1999 now U.S. Pat. No. 6,426,917, which is a continuation-in-part of U.S. application Ser. No. 09/019,466, filed on Feb. 5, 1998 now U.S. Pat. No. 6,028,534, which claims priority to U.S. Provisional Application Ser. No. 60/048,254 filed Jun. 2, 1997, and U.S. application Ser. No. 09/135,774, filed on Aug. 18, 1998 now U.S. Pat. No. 6,070,662.
1. Technical Field
The present invention relates generally to the discovery and production of hydrocarbons, and more particularly, to the monitoring of downhole formation properties during drilling and production.
2. Related Art
Wells for the production of hydrocarbons such as oil and natural gas must be carefully monitored to prevent catastrophic mishaps that are not only potentially dangerous but also that have severe environmental impacts. In general, the control of the production of oil and gas wells includes many competing issues and interests including economic efficiency, recapture of investment, safety and environmental preservation.
On one hand, to drill and establish a working well at a drill site involves significant cost. Given that many "dry holes" are dug, the wells that produce must pay for the exploration and digging costs for the dry holes and the producing wells. Accordingly, there is a strong desire to produce at a maximum rate to recoup investment costs.
On the other hand, the production of a producing well must be monitored and controlled to maximize the production over time. Production levels depend on reservoir formation characteristics such as pressure, porosity, permeability, temperature and physical layout of the reservoir and also the nature of the hydrocarbon (or other material) extracted from the formation. Additional characteristics of a producing formation must also be considered, such characteristics include the oil/water interface and the oil/gas interface, among others.
Producing hydrocarbons too quickly from one well in a producing formation relative to other wells in the producing formation (of a single reservoir) may result in stranding hydrocarbons in the formation. For example, improper production may separate an oil pool into multiple portions. In such cases, additional wells must be drilled to produce the oil from the separate pools. Unfortunately, either legal restrictions or economic considerations may not allow another well to be dug thereby stranding the pool of oil and, economically wasting its potential for revenue.
Besides monitoring certain field and production parameters to prevent economic waste of an oilfield, an oilfield's production efficiencies may be maximized by monitoring the production parameters of multiple wells for a given field. For example, if field pressure is dropping for one well in an oil field more quickly than for other wells, the production rate of that one well might be reduced. Alternatively, the production rate of the other wells might be increased. The manner of controlling production rates for different wells for one field is generally known. At issue, however, is obtaining the oil field parameters while the well is being formed and also while it is producing.
In general, control of production of oil wells is a significant concern in the petroleum industry due to the enormous expense involved. As drilling techniques become more sophisticated, monitoring and controlling production even from a specified zone or depth within a zone is an important part of modern production processes.
Consequently, sophisticated computerized controllers have been positioned at the surface of production wells for control of uphole and downhole devices such as motor valves and hydro-mechanical safety valves. Typically, microprocessor (localized) control systems are used to control production from the zones of a well. For example, these controllers are used to actuate sliding sleeves or packers by the transmission of a command from the surface to downhole electronics (e.g., microprocessor controllers) or even to electromechanical control devices placed downhole.
While it is recognized that producing wells will have increased production efficiencies and lower operating costs if surface computer based controllers or downhole microprocessor based controllers are used, their ability to control production from wells and from the zones served by multilateral wells is limited to the ability to obtain and to assimilate the oilfield parameters. For example, there is a great need for real-time oilfield parameters while an oil well is producing. Unfortunately, current systems for reliably providing real-time oilfield parameters during production are not readily available.
Moreover, many prior art systems generally require a surface platform at each well for monitoring and controlling the production at a well. The associated equipment, however, is expensive. The combined costs of the equipment and the surface platform often discourage oil field producers from installing a system to monitor and control production properly. Additionally, current technologies for reliably producing real time data do not exist. Often, production of a well must be interrupted so that a tool may be deployed into the well to take the desired measurements. Accordingly, the data obtained is expensive in that it has high opportunity costs because of the cessation of production. It also suffers from the fact that the data is not true real-time data.
Some prior art systems measure the electrical resistivity of the ground in a known manner to estimate the characteristics of the reservoir. Because the resistivity of hydrocarbons is higher than water, the measured resistivity in various locations can be of assistance in mapping out the reservoir. For example, the resistivity of hydrocarbons to water is about 100 to 1 because the formation water contains salt and, generally, is much more conductive.
Systems that map out reservoir parameters by measuring resistivity of the reservoir for a given location are not always reliable, however, because they depend upon the assumption that any present water has a salinity level that renders it more conductive that the hydrocarbons. In those situations where the salinity of the water is low, systems that measure resistivity are not as reliable.
Some prior art systems for measuring resistivity include placing an antenna within the ground for generating relatively high power signals that are transmitted through the formation to antennas at the earth surface. The amount of the received current serves to provide an indication of ground resistivity and therefore a suggestion of the formation characteristics in the path formed from the transmitting to the receiving antennas.
Other prior art systems include placing a sensor at the bottom of the well in which the sensor is electrically connected through cabling to equipment on the surface. For example, a pressure sensor is placed within the well at the bottom to attempt to measure reservoir pressure. One shortfall of this approach, however, is that the sensor does not read reservoir pressure that is unaffected by drilling equipment and formations since the sensor is placed within the well itself.
Other prior art systems include hardwired sensors placed next to or within the well casing in an attempt to reduce the effect that the well equipment has on the reservoir pressure. While such systems perhaps provide better pressure information than those in which the sensor is placed within the well itself, they still do not provide accurate pressure information that is unaffected by the well or its equipment.
Alternatives to the above systems include sensors deployed temporarily in a wireline tool system. In some prior art systems, a wireline tool is lowered to a specified location (depth), secured, and deploys a probe into engagement with the formation to obtain samples from which formation parameters may be estimated. One problem with using such wireline tools, however, is that drilling and/or production must be stopped while the wireline tool is deployed and while samples are being taken or while tests are being performed. While such wireline tools provide valuable information, significant expense results from "tripping" the well, if during drilling, or stopping production.
Thus, there exists a need in the art for a reservoir management system that efficiently senses reservoir formation parameters so that the reservoir may be drilled and produced in a controlled manner that avoids waste of the hydrocarbon resources or other resources produced from it.
To overcome the shortcomings of the prior systems and their operations, the present invention contemplates a reservoir management system including a centralized control center that communicates with a plurality of remote sensing units that are deployed in the subsurface formations of interest by way of communication circuitry located on the earth surface at the well site. According to specific implementations, the deployed remote sensing units provide formation information either to a measurement while drilling tool (MWD) or to a wireline tool. The well control unit is coupled either to a least one antenna or to a downhole data acquisition system that includes an antenna for communicating with the remote sensing units.
Because the remote sensing units are already deployed, the downtime associated with gathering remote sensing unit information via a wireline tool is minimized. Because the invention may be implemented through MWD tool, there is no downtime associated with gathering remote sensing unit information during drilling. Accordingly, formation information may be obtained more efficiently, and more frequently thereby assisting in the efficient depletion of the reservoir.
In one embodiment of the described embodiment, a central control center communicates with a plurality of well control units deployed at each well for which remote sensing units have been deployed. Some wells include a drilling tool that is in communication with at least one remote sensing unit while other wells include a wireline tool that is communication with at least one remote sensing unit. Other wells include permanently installed downhole electronics and antennas for communicating with the remote sensing units.
Each of the wells that have remote sensing units deployed therein include circuitry for receiving formation data received from the remote sensing units. In some embodiments, a well control unit serves to transpond the formation data to the central control unit. In other embodiments, an oilfield service vehicle includes transceiver circuitry for transmitting the formation data to the central control system. In an alternate embodiment, a surface unit, by way of example, a well control unit merely stores the formation data until the data is collected through a conventional method.
Some of the methods for producing the formation data to the central control center for analysis include conventional wireline links such as public switched telephone networks, computer data networks, cellular communication networks, satellite based cellular communication networks, and other radio based communication systems. Other methods include physical transportation of the formation data in a stored medium.
The central control center receives the formation data and analyzes the formation data for a plurality of wells to determine depletion rates for each of the wells so that the field may be depleted in an economic and efficient manner. In the preferred embodiment, the central control center generates control commands to the well control units. Responsive thereto, the well control units modify production according to the received control commands. Additionally, the well control units, wherever installed, continue to periodically produce formation data to the central control center so that local depletion rates may be modified if necessary.
More specifically, some of the disclosed embodiments include a downhole communication system that includes a wireline tool located within a cased well section for communicating with the remote sensing unit located outside of the casing. Accordingly, one aspect of the invention includes a casing joint that includes non-conductive electromagnetic windows that allow electromagnetic signals to be transmitted from the tool within the casing to the remote sensing unit and vice versa. In the described embodiment, the electromagnetic windows are formed to substantially circumscribe a portion of the casing to render the casing rotationally invariant to the location of the remote sensing unit. In an alternate embodiment, at least one electromagnetic window is placed on only one side of the casing thereby requiring careful placement of the casing in relation to the remote sensing unit. As a result of including a casing section that is non conductive and that passes electromagnetic signals, conventional wireline tools for cased hole applications may be made to include communication circuitry for establishing communication links with the remote sensing units so that formation data may be quickly and conveniently obtained to assist in the controlled depletion of a well within a field.
Other aspects of the present invention will become apparent with further reference to the drawings and specification that follow.
A better understanding of the present invention can be obtained when the following detailed description of the preferred embodiment is considered with the following drawings, in which:
It is generally known in the art of drilling wells to use a drilling rig 106 that employs rotary drilling techniques to form a well-bore 104 in the earth 112. The drilling rig superstructure 108 supports elevators used to lift the drill string, temporarily stores drilling pipe when it is removed from the hole, and is otherwise employed to service the well-bore 104 during drilling operations. Other structures also service the drilling rig 106 and include covered storage (e.g., a dog house), mud tanks, drill pipe storage, and various other facilities.
Drilling for the discovery and production of oil and gas may be onshore (as illustrated) or may be off-shore or otherwise upon water. When offshore drilling is performed a platform or floating structure is used to service the drilling rig. The present invention applies equally as well to both onshore and off-shore operations. For simplicity in description, onshore installations will be described.
When drilling operations commence, a casing 114 is set and attached to the earth 112 in cementing operations. A blow-out-preventer stack 116 is mounted onto the casing 114 and serves as a safety device to prevent formation pressure from overcoming the pressure exerted upon the formation by a drilling mud column. Within the well-bore 104 below the casing 114 is an uncased portion of well-bore 104 that has been drilled in the earth 112 in the drilling operations. This uncased portion of the well-bore or borehole is often referred to as the "open-hole."
In typical drilling operations, drilling commences from the earth's surface to a surface casing depth. Thereafter, the surface casing is set and drilling continues to a next depth where a second casing is set. The process is repeated until casing has been set to a desired depth. FIG. illustrates the structure of a well after one or more casing strings have been set and an open-hole segment of a well has been drilled and remains uncased.
According to the present invention, remote sensing units are deployed into formations of interest from the well-bore 104. For example, remote sensing unit 120 is deployed into subsurface formation 122, remote sensing unit 124 is deployed into subsurface formation 126 and remote sensing unit 128 is deployed into subsurface formation 130. The remote sensing units 120, 124 and 128 measure properties of their respective subsurface formations. These properties include, for example, formation pressure, formation temperature, formation porosity, formation permeability and formation bulk resistivity, among other properties. This information enables reservoir engineers and geologists to characterize and quantify the characteristics and properties of the subsurface formations 122, 126 and 130. Upon receipt, the formation data regarding the subsurface formation may be employed in computer models and other calculations to adjust production levels and to determine where additional wells should be drilled.
As contrasted to other measurements that may be made upon the formation using measurement while drilling (MWD) tools, mud logging, seismic measurements, well logging, formation samples, surface pressure and temperature measurements and other prior techniques, the remote sensing units 120, 124 and 128 remain in the subsurface formations. The remote sensing units 120, 124 and 128 therefore may be used to continually collect formation information not only during drilling but also after completion of the well and during production. Because the information collected is current and accurately reflects formation conditions, it may be used to better develop and deplete the reservoir in which the remote sensing units are deployed.
As is discussed in detail in co-pending U.S. application Ser. No. 09/019,466, filed on Feb. 5, 1998 and claiming priority to U.S. Provisional Application Serial No. 60/048,254 filed Jun. 2, 1997, and U.S. application Ser. No. 09/135,774, filed on Aug. 18, 1998 (priority is claimed to both and both are incorporated by reference), the remote sensing units 120, 124 and 128 are preferably set during open-hole operations. In one embodiment, the remote sensing units are deployed from a drill string tool that forms part of the collars of the drill string. In another embodiment, the remote sensing units are deployed from an open-hole logging tool. For particular details to the manner in which the remote sensing units are deployed, refer to the incorporated description.
The MWD tool 208 forms a portion of the drill string that also includes drill pipe 212. MWD tools 208 are generally known in the art to collect data during drilling operations. The MWD tool 208 shown forms a portion of a drill collar that resides adjacent the drill bit 216. As is known, the drill bit erodes the formation to form the well-bore 104. Drilling mud circulates down through the center of the drill string, exits the drill string through nozzles or openings in the bit, and returns up through the annulus along the sides of the drill string to remove the eroded formation pieces.
In one embodiment, the MWD tool 208 is used to deploy the remote sensing unit 204 into the subsurface formation. For this embodiment, the MWD tool 208 includes both a deployment structure and a downhole communication unit. The down-hole communication unit communicates with the remote sensing unit 204 and provides power to the remote sensing unit 204 during such communications, in a manner discussed further below. The MWD tool 208 also includes an uphole interface 220 that communicates with the down-hole communication unit. The uphole interface 220, in the described embodiment, is coupled to a satellite dish 224 that enables communication between the MWD tool 208 and a remote site. In other embodiments, the MWD tool 208 communicates with a remote site via a radio interface, a telephone interface, a cellular telephone interface or a combination of these so that data captured by the MWD tool 208 will be available at a remote location.
As will be further described herein, the remote sensing units may be constructed to be solely battery powered, or may be constructed to be remotely powered from a down-hole communication unit in the well-bore, or to have a combination of both (as in the described embodiments). Because no physical connection exists between the remote sensing unit 204 and the MWD tool 208, however, an electromagnetic (e.g., Radio Frequency "RF") link is established between the MWD tool 208 and the remote sensing unit 204 for the purpose of communicating with the remote sensing unit. In some embodiments, an electromagnetic link also is established to provide power to the remote sensing unit. In a typical operation, the coupling of an electromagnetic signal having a frequency of between 1 and 10 Megahertz will most efficiently allow the MWD tool 208 (or another downhole communication unit) to communicate with, and to provide power to the remote sensing unit 204.
With the remote sensing unit 204 located in a subsurface formation adjacent the well-bore 104, the MWD tool 208 is located in close proximity to the remote sensing unit 204. Then, power-up and/or communication operations are begun. When the remote sensing unit 204 is not battery powered or the battery is at least partially depleted, power from the MWD tool 208 that is electromagnetically coupled to the remote sensing unit 204 is used to power up the remote sensing unit 204. More specifically, the remote sensing unit 204 receives the power, charges a capacitor that will serve as its power source and commences power-up operations. Once the remote sensing unit 204 has received a specified or sufficient amount of power, it performs self-calibration operations and then makes formation measurements. These formation measurements are recorded and then communicated back to the MWD tool 208 via the electromagnetic coupling.
As is generally known, open-hole wireline operations are performed during the drilling of wells to collect information regarding formations penetrated by well-bore 104. In such wireline operations, a wireline truck 252 couples to a wireline tool 256 via an armored cable 260 that includes a conduit for conducting communication signals and power signals. Armored cable 260 serves both to physically couple the wireline tool 256 to the wireline truck 252 and to allow electronics contained within the wireline truck 252 to communicate with the wireline tool 256.
Measurements taken during wireline operations include formation resistivity (or conductivity) logs, natural radiation logs, electrical potential logs, density logs (gamma ray and neutron), micro-resistivity logs, electromagnetic propagation logs, diameter logs, formation tests, formation sampling and other measurements. The data collected in these wireline operations may be coupled to a remote location via an antenna 254 that employs RF communications (e.g., two-way radio, cellular communications, etc.).
According to the present invention, the remote sensing unit 204 may be deployed from the wireline tool 256. Further, after deployment, data may be retrieved from the remote sensing unit 204 via the wireline tool 256. In such embodiments, the wireline tool 256 is constructed so that it couples electromagnetically with the remote sensing unit 204. In such case, the wireline tool 256 is lowered into the well-bore 104 until it is proximate to the remote sensing unit 204. The remote sensing unit 204 will typically have a radioactive signature that allows the wireline tool 256 to sense its location in the well-bore 104.
With remote sensing unit 204 located within well-bore 104, wireline tool 256 is placed adjacent remote sensing unit 204. Then, power-up and/or communication operations proceed. When remote sensing unit 204 is not battery powered or the battery is at least partially depleted, power from wireline tool 256 is electromagnetically transmitted to remote sensing unit 204. Remote sensing unit 204 receives the power, charges a capacitor that will serve as its power source and commences power-up operations. When remote sensing unit 204 has been powered, it performs self-calibration operations and then makes subsurface formation measurements. The subsurface formation measurements are stored and then transmitted to wireline tool 256. Wireline tool 256 transmits this data back to wireline truck 252 via armored cable 260. The data may be stored for future use or it may be immediately transmitted to a remote location for use.
Once the well has been fully drilled, casing 312 is set in place and cemented to the formation. A production stack 316 is attached to the top of casing 312, the well is perforated in at least one producing zone and production commences. The production of the well is monitored (as are other wells in the reservoir) to manage depletion of the reservoir.
During drilling of the well, or during subsequent open-hole wireline operations, the remote sensing unit 304 is deployed into a subsurface formation that becomes a producing zone. Thus, the properties of this formation are of interest throughout the life of the well and also throughout the life of the reservoir. By monitoring the properties of the producing zone at the location of the well and the properties of the producing zone in other wells within the field, production may be managed so that the reservoir is more efficiently depleted.
As illustrated in
According to one aspect of the present invention, when the casing 312 is set, special casing sections are set adjacent the remote sensing unit 304. As will be described further with reference to
Referring back to
As compared to the wireline operations, however, downhole communication unit 354 remains downhole within the casing 312 for a long period of time (e.g., time between maintenance operations or while the data being collected is of value in reservoir management). Communication coupling and physical coupling to downhole communication unit 354 is performed via an armored cable 362. The well control unit 358 communicatively couples to the downhole communication unit 354 to collect and store data. This data may then be relayed to a remote location via antenna 360 over a supported wireless link.
For example, installations 406, 410 and 414 are shown to reside in producing wells. In such installations 406, 410 and 414, data is at least periodically measured and collected for use at the central control center 402. In contrast, installations 416 and 418 are shown to be at newly drilled wells that have not yet been cased.
In the management of a large reservoir, literally hundreds of installations may be used to monitor formation properties across the reservoir. Thus, while some wells are within a range that allows the use of ordinary RF equipment for uploading remote sensing unit 404 data, other wells are a great distance away. Satellite based installation 418 illustrates such a well where a satellite dish is required to upload data from remote sensing unit 404 to satellite 422. Additionally, central control center 402 also includes a satellite dish 424 for downloading remote sensing unit 402 data from satellite 422.
Data that is collected from the installations 406-418 may be relayed to the central control center 402 via wireless links, via wired links and via physical delivery of the data. To support wireless links, the central control center 402 includes an RF tower 426, as well as the satellite dish 424, for communicating with the installations. RF tower 426 may employ antennas for any known communication network for transceiving data and control commands including any of the cellular communication systems (AMPS, TDMA, CDMA, etc.) or RF communications.
Central control center 402 includes circuitry for transceiving data and control commands to and from the installations 406-418. Additionally, central control center 402 also includes processing equipment for storing and analyzing the subsurface formation property measurements collected at the installations by the remote sensing units 404. This data may be used as input to computer programs that model the reservoir. Other inputs to the computer programs may include seismic data, well logs (from wireline operations), and production data, among other inputs. With the additional data input, the computer programs may more accurately model the reservoir.
Accurate computer modeling of the reservoir, that is made possible by accurate and real time remote sensing unit 404 data in conjunction with a reservoir management system as described herein, allow field operators to manage the reservoir more effectively so that it may be depleted efficiently thereby providing a better return on investment. For example, by using the more accurate computer models to manage production levels of existing wells, to determine the placement of new wells, to control water flooding and other production events, the reservoir may be more fully depleted of its valuable oil and gas.
Referring now to
The remote sensing units 524 are encapsulated "intelligent" remote sensing units which are moved from the drill collar to a position in the formation surrounding the borehole for sensing formation parameters such as pressure, temperature, rock permeability, porosity, conductivity and dielectric constant, among others. The remote sensing units 524 are appropriately encapsulated in a remote sensing unit housing of sufficient structural integrity to withstand damage during movement from the drill collar into laterally embedded relation with the subsurface formation surrounding the well bore. By way of example, the remote sensing units are partially formed of a tungsten-nickel-iron alloy with a zirconium end plate. The zirconium end plate specifically is formed of a non-metallic material so that electromagnetic signals may be transmitted through it. Patent application Ser. No. 09/293,859 filed on Apr. 16, 1999 fully describes the mechanical aspects of the remote sensing units 524 and is included by reference herein for all purposes.
Those skilled in the art will appreciate that such lateral imbedding movement need not be perpendicular to the borehole, but may be accomplished through numerous angles of attack into the desired formation position. Remote sensing unit deployment can be achieved by utilizing one or a combination of the following: (1) drilling into the borehole wall and placing the remote sensing unit into the formation; (2) punching/pressing the encapsulated remote sensing unit into the formation with a hydraulic press or mechanical penetration assembly; or (3) shooting the encapsulated remote sensing units into the formation by utilizing propellant charges.
As shown in
Referring now to
With reference to
A battery 866 also is provided within the remote sensing unit circuitry 844 and is coupled with the various circuitry components of the remote sensing unit by power conductors 868, 870 and 872. While the described embodiment of
Referring now to
Throughout the complete transmission sequence, the transmitter/receiver coil 538, shown in
Assuming that the remote sensing unit 524 is in place inside the formation to be monitored, the sequence in which the transmission and the acquisition electronics function in conjunction with drilling operations is as follows:
The drill collar with its acquisition sensors is positioned in close proximity of the remote sensing unit 524. An electromagnetic wave having a frequency F, as shown at 1084 in
Whenever the sequence above is initiated, the transmitter/receiver coil 538 located within the instrumentation section of the drill collar is powered by the transmitter power drive or amplifier 540. And electromagnetic wave is transmitted from the drill collar at a frequency F determined by the oscillator 542, as indicated in the timing diagram of
In contrast to present-day operations, the present invention makes pressure data and other formation parameters available while drilling, and, as such, allows well drilling personnel to make decisions concerning drilling mud weight and composition as well as other parameters at a much earlier time in the drilling process without necessitating the tripping of the drill string for the purpose of running a formation tester instrument. The present invention requires very little time to gather the formation data measurements. Once a remote sensing unit 524 is deployed, data can be obtained while drilling, a feature that is not possible according to known well drilling techniques.
Time dependent pressure monitoring of penetrated well bore formations can also be achieved as long as pressured data from the pressure sensor 518 is available. This feature is dependent of course on the communication link between the transmitter/receiver circuitry within the power cartridge of the drill collar and any deployed intelligent remote sensing units 524.
The remote sensing unit output can also be read with wireline logging tools during standard logging operations. This feature of the invention permits varying data conditions of the subsurface formation to be acquired by the electronics of logging tools in addition to the real time formation data that is now obtainable while drilling.
By positioning be intelligent remote sensing units 524 beyond the immediate borehole environment, at least in the initial data acquisition period there will be very little borehole effects on the noticeable pressure measurements that are taken. As extremely small liquid movement is necessary to obtain formation pressures with in-situ sensors, it will be possible to measure formation pressure in fluid bearing non-permeable formations. Those skilled in the art will appreciate that the present invention is equally adaptable for measurements of several formation parameters, such as permeability, conductivity, dielectric constant, rocks strength, and others, and is not limited to formation pressured measurement.
As indicated previously, deployment of a desired number of such remote sensing units 524 occurs at various well-bore depths as determined by the desired level of formation data. As long as the well-bore remains open, or uncased, the deployed remote sensing units may communicate directly with the drill collar, sonde, or wireline tool containing a data receiver, also described in the '466 application, to transmit data indicative of formation parameters to a memory module on the data receiver for temporary storage or directly to the surface via the data receiver.
At some point during the completion of the well, the well-bore is completely cased and, typically, the casing is cemented in place. From this point, normal communication with deployed remote sensing units 524 that lie in formation 506 beyond the well-bore is no longer possible. Thus, communication must be reestablished with the deployed remote sensing units through the casing wall and cement layer, if the latter is present, that line the well-bore.
With reference now to
To permit the location of the remote sensing units 524 to be identified, the remote sensing units 524 are equipped with a radiation source for transmitting respective identifying signature signals. More specifically, the remote sensing units 524 are equipped with a gamma-ray pip-tag 1121 for transmitting a pip-tag signature signal. The pip-tag is a small strip of paper-like material that is saturated with a radioactive solution and positioned within remote sensing unit 524, so as to radiate gamma rays.
The location of each remote sensing unit is then identified through a two-step process. First, the depth of the remote sensing unit is determined using a gamma-ray open hole log, which is created for the well-bore after the deployment of remote sensing units 524, and the known pip-tag signature signal of the remote sensing unit. The remote sensing unit will be identifiable on the open-hole log because the radioactive emission of pip-tag 1121 will cause the local ambient gamma-ray background to be increased in the region of the remote sensing unit. Thus, background gamma-rays will be distinctive on the log at the remote sensing unit location, compared to the formation zones above and below the remote sensing unit. This will help to identify the vertical depth and position of the remote sensing unit.
The azimuth of the remote sensing unit relative to the well-bore is determined using a gamma-ray detector and the remote sensing unit's pip-tag signature signal. The azimuth is determined using a collimated gamma-ray detector, as described further below in the context of a multi-functional wireline tool.
Antenna 1128 is preferably installed and sealed in opening 1122 in the casing using a wireline tool. The wireline tool, generally referred to as 1230 in
Wireline tool 1230 is lowered on a wireline or cable 1231, the length of which determines the depth of tool 1230 in the well-bore. Depth gauges may be used to measure displacement of the cable over a support mechanism, such as a sheave wheel, and thus indicate the depth of the wireline tool in a manner that is well known in the art. In this manner, wireline tool 1230 is positioned at the depth of remote sensing unit 524. The depth of wireline tool 1230 may also be measured by electrical, nuclear, or other sensors that correlate depth to previous measurements made in the well-bore or to the well casing length.
Cable 1231 also provides cable strands for communicating with control and processing equipment positioned at the surface via circuitry carried in the cable. In the described embodiment, the cable strands of cable 1231 comprise metallic wiring. Any known medium for conducting communication signals to underground equipment is specifically included herein.
The wireline tool further includes the upper and lower rotation tools 1234 and 1236 for rotating wireline tool 1230 to the identified azimuth, after having been lowered to the proper remote sensing unit depth as determined from the first step of the remote sensing unit location identification process. One embodiment of a simple rotation tool, as illustrated by lower rotation tool 1236 in
The two drive wheels of each rotation tool are driven, respectively, via a gear train, such as gears 1345 a and 1345 b, by electric servo motor 1250. Primary gear 1345 a is connected to the motor output shaft for rotation therewith. The rotating force is transmitted to drive wheels 1342, 1344 via secondary gears 1345 b, and friction between the drive wheels and the inner casing wall induces wireline tool 1230 to rotate as drive wheels 1342 and 1344 "crawl" about the inner wall of casing 1224. This driving action is performed by both the upper and lower rotation tools 1234 and 1236 to enable rotation of the entire wireline tool assembly 1230 within casing 1124 about the longitudinal axis of the casing.
Antenna installation tool 1238 includes circuitry for identifying the azimuth of remote sensing unit 524 relative to well-bore WB in the form of collimated gamma-ray detector 1332, thereby providing for the second step of the remote sensing unit location identification process. As indicated previously, collimated gamma-ray detector 1332 is useful for detecting the radiation signature of anything placed in its zone of detection. The collimated gamma-ray detector, which is well known in the drilling industry, is equipped with shielding material positioned about a thallium-activated sodium iodide crystal except for a small open area at the detector window. The open area is accurate, and is narrowly defined for precise identification of the remote sensing unit azimuth.
Thus, a rotation of 360 degrees by wireline tool 1230, under the output torque of motor 1250, within casing 1124 reveals a lateral radiation pattern at any particular depth where the wireline tool, or more particularly the collimated gamma-ray detector, is positioned. By positioning the gamma-ray detector at the depth of remote sensing unit 524, the lateral radiation pattern will include the remote sensing unit's gamma-ray signature against a measured baseline. The measured baseline is related to the amount of detected gamma-rays corresponding to the respective local formation background. The pip-tag of each remote sensing unit 524 will give a strong signal on top of this baseline and identify the azimuth at which the remote sensing unit is located, as represented in FIG. 14. In this manner, antenna installation tool 1238 can be "pointed" very closely to the remote sensing unit of interest.
Further operation of tool 1230 is highlighted by the flow chart sequence of
Referring back to
The first subsystem of inner housing 1514 includes flexible shaft 1518 conveyed through mating guide plates 1542, one of which is shown in FIG. 15A. Drill bit 1519 is rotated via flexible shaft 1518 by drive motor 1520, which is held by motor bracket 1521. Motor bracket 1521 is attached to translation motor 1522 by way of threaded shaft 1523 which engages nut 1521 a connected to motor bracket 1521. Thus, translation motor 1522 rotates threaded shaft 1523 to move drive motor 1520 up and down relative to inner housing 1514 and casing 1224. Downward movement of drive motor 1520 applies a downward force on flexible shaft 1518, increasing the penetration rate of bit 1519 through casing 1124. J-shaped conduit 1543 formed in guide plates 1542 translates the downward force applied to shaft 1518 into a lateral force at bit 1519, and also prevents shaft 1518 from buckling under the thrust load it applies to the bit.
As the bit penetrates the casing, it makes a clean, uniform perforation that is much preferred to that obtainable with shaped charges. The drilling operation is represented by step 1603 in FIG. 16. After the casing perforation has been drilled, drill bit 1519 is withdrawn by reversing the direction of translation motor 1522. It is understood, of course, that prior to the drilling step that packer setting piston 1524 b is actuated to force packer 1517 c against the inner wall of housing 1517, forming a sealed passageway between the casing perforation and flowline 1524 (step 1602).
The second subsystem of inner housing 1514 relates to the testing of the pressure seal at the casing. For this purpose, housing translation piston 1516 is energized from surface control equipment via circuitry passing through cable 1231 to shift inner housing 1514 upwardly so as to move packer 1517 c about the opening in housing 1517. The formation pressure can then be measured in a conventional manner, and a fluid sample can be obtained if so desired (step 1604). Once the proper measurements and samples have been taken, piston 224 b is withdrawn to retract packer 217 c (step 1605).
Housing translation piston 1516 is then actuated to shift inner housing 1514 upwardly even further to align antenna magazine 1526 in position over the casing perforation (step 1606). Antenna setting piston 1525 is then actuated to force one antenna 1128 from magazine 1526 into the casing perforation. The sequence of setting the antenna is shown more particularly in
With reference first to
Tapered antenna body 1877 is equipped with elongated antenna pin 1877 a, tapered insulating sleeve 1877 b, and outer insulating layer 1877 c, as shown in FIG. 18C. Antenna pin 1877 a extends beyond the width of casing perforation 1822 on each end of the pin to receive data signals from remote sensing unit 524 and communicate the signals to a data receiver positioned in the well-bore, as described in detail below. Insulating sleeve 1877 b is tapered near the leading end of the antenna pin to form an interference wedge-like fit within the tapered opening at the leading end of tubular socket 1876, thereby providing a pressure-tight seal at the antenna/perforation interface.
Magazine 1526, as shown in
An alternative antenna structure is shown in FIG. 18D. In this embodiment, antenna pin 1812 is permanently set in insulating sleeve 1814, which in turn is permanently set in setting cone 1816. Insulating sleeve 1814 is cylindrical in shape, and setting cone 1816 has a conical outer surface and a cylindrical bore therein sized for receiving the outer diameter of sleeve 1814. Setting sleeve 1818 has a conical inner bore therein that is sized to receive the outer conical surface of setting cone 1816, and the outer surface of sleeve 1818 is slightly tapered so as to facilitate its insertion into casing perforation 1822. By the application of opposing forces to cone 1816 and sleeve 1818, a metal-to-metal interference fit is achieved to seal antenna assembly 1810 in perforation 1822. The application of force via opposing hydraulically actuated pistons in the direction of the arrows shown in
The integrity of the installed antenna, whether it be the configuration of
Referring now to
More particularly, communication between data receiver 2060 inside casing 1124 and remote sensing unit 524 located outside the casing is achieved in a preferred embodiment via two small loop antennas 2014 a and 2014 b. The antennas are imbedded in antenna assembly 1128 that has been placed inside opening 1122 by antenna installation tool 1238. A plane formed by first antenna loop 2014 a is positioned parallel to a longitudinal axis of the casing and produces a magnetic dipole that is perpendicular to the longitudinal axis of the casing. The second antenna loop 2014 b is positioned to produce a magnetic dipole that is perpendicular to the longitudinal axis of the casing as well as the magnetic dipole produced by the first antenna loop 2014 a. Consequently, first antenna 2014 a is sensitive to electromagnetic fields perpendicular to the casing axis and second antenna 2014 b is sensitive to magnetic fields parallel to the axis of the casing.
Remote sensing unit 524, contains in a preferred embodiment, two similar loop antennas 2015 a and 2015 b therein. The loop antennas have the same relative orientation to one another as loop antennas 2014 a and 2014 b. However, loop antennas 2015 a and 2015 b are connected in series, as indicated in
The data receiver in the tool inside the casing utilizes a microwave cavity 2062 having a window 2064 adapted for close positioning against the inner face of casing wall 2024. The radius of curvature of the cavity is identical or very close to the casing inner radius so that a large portion of the window surface area is in contact with the inner casing wall. The casing effectively closes microwave cavity 2062, except for drilled opening 1122 against which the front of window 2064 is positioned. Such positioning can be achieved through the use of components similar to those described above in regard to wireline tool 1230, such as the rotation tools, gamma-ray detector, and anchor pistons. (No further description of such data receiver positioning will be provided herein.) Through the alignment of window 2064 with perforation 1122, energy such as microwave energy can be radiated in and out via the antenna through the opening in the casing, providing a means for two-way communication between sensing microwave cavity 2062 and the remote sensing unit antennas 2015 a and 2015 b.
Communication from the microwave cavity is provided at one frequency F corresponding to one specific resonant mode, while communication from the remote sensing unit is achieved at twice the frequency, or 2F. Dimensions of the cavity are chosen to have resonant frequencies close to 1F and 2F. Those skilled in the art can appreciate to formation of cavities to have such specified resonant frequency characteristics. Relevant electrical fields 2066, 2068 and magnetic fields 2070, 2062 are illustrated in
In transmitting mode, cavity 2062 is excited by microwave energy fed from the transmitter oscillator 2074 and power amplifier 2076 through connection 2078, a coaxial line connected to a small electrical dipole located at the top of cavity 2062 of data receiver 2060.
In a receiving mode, microwave energy excited in cavity 2062 at a frequency 2F is sensed by the vertical magnetic dipole 2080 connected to a receiver amplifier 2082 tuned at 2F.
It is a well known fact that microwave cavities have two fundamental modes of resonance. The first one is called transverse magnetic or "TM" (Hz=0), and the second mode is called transverse electric or "TE" in short (Ez=0). These two modes are therefore orthogonal and can be distinguished not only by frequency discrimination but also by the physical orientation of an electric or magnetic dipole located inside the cavity to either excite or detect them, a feature that the present invention uses to separate signals excited at frequency F from signals excited at 2F.
At resonance, the cavity displays a high Q, or dampening loss effect, when the frequency of the EM field inside the cavity is close to the resonant frequency, and a very low Q when the frequency of the EM field inside the cavity is different from the resonant frequency of the cavity, providing additional amplification of each mode and isolation between different modes.
Mathematical expressions for the electrical (E) and magnetic (H) field components of the TM and TE modes are given by the following terms:
For TM Modes
One solution for FTEnim is to select the TE mode corresponding to n=2, i=1, m=1 and G21=3.0542. This selection is orthogonal to the TM010 mode selection above, and produces a frequency for the TE mode that is twice the TM010 frequency. The following results are produced by this TE mode selection:
The TM mode can be excited either by a vertical electric dipole (Ez) or a horizontal magnetic dipole (vertical loop Hφ), while the TE mode can be excited by a vertical magnetic dipole (horizontal loop Hz).
Those of ordinary skill in the related art given the benefit of this disclosure will appreciate that with change in cavity shape, dimensions and filling material, the exact values of the resonant frequencies may differ from those stated above. It should also be understood that the two modes described earlier are just one possible set of resonant modes and that there is, in principle, an infinite set one might choose from. In any case, the preferable frequency range for this invention falls in the 100 MHz to 10 GHz range. It should also be understood that the frequency range could be extended outside this preferred range without departing from the spirit of the present invention.
It is also well known that a cavity can be excited by proper placement of an electrical dipole, magnetic dipole, an aperture (i.e., an insulated slot on a conductive surface) or a combination of these inside the cavity or on the outer surface of the cavity. For instance, coupling loop antennas 2014 a and 2014 b could be replaced by electrical dipoles or by a simple aperture. The remote sensing unit loop antennas could also be replaced by a single or combination of electrical and/or magnetic dipole(s) and/or aperture(s).
In order to determine if oscillator frequency F is tuned to the TM010 resonant frequency of cavity 2062, horizontal magnetic dipole 2288, a small vertical loop sensitive to HφTM101 (equation (2) below), is connected through a coaxial cable to switch 2281 and, via switch 2281, to a microwave receiver amplifier 2290 tuned at F. The frequency F is adjusted until a maximum signal is received in tuned receiver 2290 by means of feedback.
It should be clear from the previous description that with change in cavity shape, dimensions and filling material, the exact values of the resonant frequencies may differ from those stated above. It should be also understood that the two modes described earlier are just one possible set of resonant modes and that there is in principle an infinite set one might choose from. In any case the preferable frequency range for this invention would fall in the 100 MHz to 10 GHz. It should also be understood that the frequency range could be extended outside this preferred range without departing from the spirit of the present invention.
Finally it is well known that a cavity can be excited by proper placement of electrical, magnetic dipole and aperture or a combination of these inside the cavity or on its outer surface. For instance coupling antennas (1 a) and (1 b) could be replaced by electrical dipoles or by a simple aperture. The remote sensing unit antenna could also be replaced by a single or combination of electrical and/or magnetic dipole(s) and/or aperture(s).
Those of ordinary skill in the related art given the benefit of this disclosure will appreciate that with change in cavity shape, dimensions and filling material, the exact values of the resonant frequencies may differ from those stated above. It should also be understood that the two modes described earlier are just one possible set of resonant modes and that there is, in principle, an infinite set one might choose from. In any case, the preferable frequency range for this invention falls in the 100 MHz to 10 GHz range. It should also be understood that the frequency range could be extended outside this preferred range without departing from the spirit of the present invention.
It is also well known that a cavity can be excited by proper placement of an electrical dipole, magnetic dipole, an aperture (i.e., an insulated slot on a conductive surface) or a combination of these inside the cavity or on the outer surface of the cavity. For instance, coupling loop antennas 2014 a and 2014 b could be replaced by electrical dipoles or by a simple aperture. The remote sensing unit loop antennas could also be replaced by a single or combination of electrical and/or magnetic dipole(s) and/or aperture(s).
In order to tune the cavity to TE211 mode frequency 2F, a 2F tuning signal is generated in tuner circuit 2284 by rectifying a signal at frequency F coming from oscillator 2274 through switch 2285 by means of a diode similar to diode 2019 used with remote sensing unit 524. The output of tuner 2284 is coupled through a coaxial cable to a vertical magnetic dipole, a small horizontal loop sensitive to Hz of TE211 (equation (4) above), to excite the TE211 mode at frequency 2F. A similar horizontal magnetic dipole is created by a small horizontal loop also sensitive to Hz of TE211 (equation (4)), that is connected to a microwave receiver circuit 2282 tuned at 2F. The output of receiver 2282 is connected to motor control 2292 which drives an electrical motor 2294 moving a piston 2296 in order to change the length L of the cavity, in a manner that is known for tunable microwave cavities, until a maximum signal is received. It will be apparent to those of ordinary skill in the art that a single loop antenna could replace the pair of loop antennas connected to both circuits 2282 and 2284.
Once both TM frequency F and TE frequency 2F are tuned, the measurement cycle can begin, assuming that the window 2264 of cavity 2262 has been positioned in the direction of remote sensing unit 524 and that antenna 1128 containing loop antennas 2014 a and 2014 b, or other equivalent means of communication, has been properly installed in casing opening 1122. Maximum coupling can be achieved for the TE211 mode if remote sensing unit 524 is positioned such that antenna 1128 is approximately level with the vertical center of microwave cavity 2262. In this regard, it should be noted that HφTM010 is independent of z, but HzTE211 is at a maximum for z=L/2.
With continuing reference to
As soon as remote sensing unit 524 is energized by the transmitted microwave energy, the receiver loop antennas 2215 a and 2215 b located inside the remote sensing unit radiate back an electromagnetic wave at 2F or twice the original frequency, as indicated at 1086 in
More specifically, and with reference now to
Referring again to
After the pressure gage or other digital information has been detected and stored in the data receiver electronics, the tool power transmitter is shut off. The target remote sensing unit is no longer energized and is switched back to its "sleep" mode until the next acquisition is initiated by the data receiver tool. A small battery 2312 located inside the remote sensing unit powers the associated electronics during acquisition and transmission.
In the described embodiment, the data acquisition circuitry 2410 includes temperature sampling circuitry 2412 for determining the temperature of the subsurface formation and pressure sampling circuitry 2414 for determining the fluid pressure of the subsurface formation. Such temperature and pressure sampling circuitry 2412 and 2414 are well known. In alternate embodiments of the invention, the downhole subsurface formation remote sensing unit 2400 data acquisition circuitry 2410 may include only one of the temperature or pressure sampling circuitry 2412 or 2414, respectively, or may include an alternate type of data sampling circuitry. What data sampling circuitry is included is dependant upon design choices and all variations are specifically included herein.
Remote sensing unit 2400 also includes communication circuitry 2420. In the described embodiment of the invention, the communication circuitry 2420 transceives electromagnetic signals via an antenna 2422 Communication circuitry 2420 includes a demodulator 2424 coupled to receive and demodulate communication signals received on antenna 2422, an RF oscillator 2426 for defining the frequency transmission characteristics of a transmitted signal, and a modulator 2428 coupled to the RF oscillator 2426 and to the antenna 2422 for transmitting modulated data signals having a frequency characteristic determined by the RF oscillator 2426.
While the described embodiment of remote sensing unit 2400 includes demodulation circuitry for receiving and interpreting control commands from an external transceiver, an alternate embodiment of remote sensing unit 2400 does not include such a demodulator. The alternate embodiment merely includes logic to transmit all types of remote sensing unit data acquisition data whenever the remote sensing unit is in a data sampling and transmitting mode of operation. More specifically, when a power supply 2430 of the remote sensing unit 2400 has sufficient charge and there is data to be transmitted and RF power is not being received from an external source, the communication circuitry merely transmits acquired subsurface formation data.
As may be seen from examining
Those skilled in the art will appreciate that, once remote sensing units have been deployed into the well-bore formation and have provided data acquisition capabilities through measurements such as pressure measurements while drilling in an open well-bore, it will be desirable to continue using the remote sensing units after casing has been installed into the wellbore. The invention disclosed herein describes a method and apparatus for communicating with the remote sensing units behind the casing, permitting such remote sensing units to be used for continued monitoring of formation parameters such as pressure, temperature, and permeability during production of the well.
It will be further appreciated by those skilled in the art that the most common use of the present invention will likely be within 8˝ inch well-bores in association with 6ľ inch drill collars. For optimization and ensured success in the deployment of remote sensing units 2400, several interrelating parameters must be modeled and evaluated. These include: formation penetration resistance versus required formation penetration depth; deployment "gun" system parameters and requirements versus available space in the drill collar; remote sensing unit ("bullet") velocity versus impact deceleration; and others.
Many well-bores are smaller than or equal to 8˝ inches in diameter. For well-bores larger than 8˝ inches, larger remote sensing units can be utilized in the deployment system, particularly at shallower depths where the penetration resistance of the formation is reduced. Thus, it is conceivable that for well-bore sizes above 8˝ inches, that remote sensing units will: be larger in size; accommodate more electrical features; be capable of communication at a greater distance from the well-bore; be capable of performing multiple measurements, such as resistivity, nuclear magnetic resonance probe, accelerometer functions; and be capable of acting as data relay stations for remote sensing units located even further from the well-bore.
However, it is contemplated that future development of miniaturized components will likely reduce or eliminate such limitations related to well-bore size.
Referring now to
Antenna 2530 is arranged in a plane that is substantially perpendicular compared with the planes defined by antennas 2514 and 2518. Antenna 2530 represents a coil antenna of a remote sensing unit 2400. While antenna 2530 is illustrated as a single coil, it is understood that the diagram is merely illustrative of a plurality of coils about a core and that the location of antenna 2530 is a representative location of the coils of the antenna of the remote sensing unit 2400. As may also be seen, antenna 2530 is separated from a vertical axis 2534 passing through the radial center of antennas 2514 and 2518 by a distance d2. Generally speaking, it is desirable for distance d2 to be less than twice the distance d1. Accordingly, antennas 2514 and 2518 are formed to be separated by a distance d1 that is roughly greater than or equal to the expected distance d2.
Moreover, for optimal communication signal and power transfer from antennas 2514 and 2518, antenna 2530 of the remote sensing unit should be placed equidistant from antennas 2514 and 2518. The reason for this is that the electromagnetically transmitted signals are strongest in the plane that is coplanar and equidistant from antennas 2514 and 2518. The principle that the highest transmission power occurs an equidistant coplanar plane is illustrated by the loops shown generally at 2538. Hφ1 is the magnetic field generated by antenna 2514; Hφ2 is the magnetic field generated by antenna 2518. In this configuration an optimal zone for coupling the antenna coils 2514 and 2518 to antenna coil 2530 exists when d2 is less than or equal to d1. Once d2 exceeds d1, the coupling between the antenna coils 2514 and 2518 and antenna coil 2530 drops of rapidly.
The antennas 2514, 2518 and 2530 of the preferred embodiment are constructed to include windings about a ferrite core. The ferrite core enhances the electromagnetic radiation from the antennas. More specifically, the ferrite improves the sensitivity of the antennas by a factor of 2 to 3 by reducing the magnetic reluctance of the flux path through the coil.
The described antenna arrangement is similar to a Helmholtz coil in that it includes a pair of antenna elements arranged in a planarly parallel fashion. Contrary to Helmholtz coil arrangements, however, the current in each antenna portion is conducted in opposite directions. While only two antennas are described herein, alternate embodiments include having multiple antenna turns. In these alternate embodiments, however, the multiple antenna turns are formed in even pairs that are axially separated.
The antenna formed by the ferrite core and the windings is functionally illustrated by a dashed line 2530 that represents the antenna. Antenna 2530 functionally illustrates that it is to be oriented perpendicularly to antenna 2718 to efficiently receive electromagnetic radiation therefrom. As may also be seen, antenna 2530 is approximately equidistant from the plurality of coils of antenna 2718 of the tool 2714. As is described in further detail elsewhere in this application, tool 2714 is lowered to a depth within well-bore 2734 to optimize communications with and power transfer to remote sensing unit 2400. This optimum depth is one that results in antenna 2530 being approximately equidistant from the coils of antenna 2718.
In the embodiment of the invention shown here in
Continuing to refer to
While the described embodiment of
Ordinarily, remote sensing units 2400 will be deployed during open hole drilling operations. After drilling operations, however, the well-bore is ordinarily cased and cemented. Because casing is typically formed of a metal, high frequency electromagnetic radiation cannot be transmitted through the casing. Accordingly, the casing according to the present invention employs at least one casing section or joint to allow a wireline tool within the casing to communicate with a remote sensing unit through a wireless electromagnetic medium.
Casing section 2910 includes at least one electromagnetic window 2922 formed of an insulative material that can pass electromagnetic signals. The at least one electromagnetic window 2922 is formed within a "short" casing joint (12 feet in the described embodiment). The non-conductive or insulative material from which the at least one window, is formed, in the described embodiment, out of an epoxy compound combined with carbon fibers (for added strength) or of a fiberglass. Experiments show that electromagnetic signals may be successfully transmitted from within a metal casing to an external receiver if the casing includes at least one non-conductive window.
In the embodiment of
The embodiment of
As may be seen, similar to other embodiments, casing section 3010 is positioned proximate to remote sensing unit 2400. Additionally, each of the antenna sections 3022 are approximately equidistant from the antenna (not shown) of remote sensing unit 2400. As with other antenna configurations, current is conducted in the antenna sections in opposite directions relative to each other.
Continuing to refer to
As may be seen, because there is only one wire 3122 for transmitting power and superimposed communication signals to the communication module 3014, the return path is established by a short lead 3123 connecting coil 3114 to casing section 2914 at 2915 above casing section 3110. This embodiment of the invention is not preferred, however, because of power transfer inefficiencies.
As may be seen, similar to other embodiments, casing section 3110 is formed proximate to remote sensing unit 2400. This embodiment of the invention, as may be seen from examining
The output of transmitter power drive 3208 is connected to a first port of a switch 3216. A second port of switch 3216 is connected to an input of a tuned receiver 3220. Tuned receiver 3220 includes an output connected to a demodulator 3224. A third port of switch 3216 is connected to an antenna 3228 that is provided for communicating with and delivering power to remote sensing unit 2400. Switch 3216 also includes a control port for receiving a control signal from a logic device 3232. Logic device 3232 generates control signals to switch 3216 to prompt switch 3216 to switch into one of a plurality of switch positions. In the described embodiment, a control signal having a first state that causes switch 3216 to connect transmitter power drive 3208 to antenna 3228. A control signal having a second state causes switch 3216 to connect tuned receiver 3220 to antenna 3228. Accordingly, logic device 3232 controls whether power and communication signal transceiver system 3200 is in a transmit or in a receive mode of operation. Finally, power and communication signal transceiver system 3200 includes an input port 3236 for receiving communication signals that are to be transmitted to the remote sensing unit 2400 and an output port 3240 for outputting demodulated signals received from remote sensing unit 2400.
The circuitry of the remote sensing unit shown in
Continuing to refer to
In operation, signal received at antenna 3308 is converted from RF to DC to charge a capacitor within power supply 3304 in a manner that is known by those skilled in the art of power supplies. Once the capacitor is charged to a specified level, power supply 3304 provides power to demodulator 3312 and data acquisition circuitry 3322 to allow them to demodulate and interpret the communication signal received over antenna 3308. If, by way of example, the communication signal requests pressure information, data acquisition circuitry interprets the request for pressure information, acquires pressure data from one of a plurality of coupled sensors 3330, stores the acquired pressure data, and provides it to modulator 3314 so that the data can be transmitted over antenna 3308 to the remote system requesting the information.
While the foregoing description is for an overall process, the actual process may vary some. By way of example, if the charge levels of the power supply drop below a specified threshold before the modulator is through transmitting the requested pressure information, the logic device 3318 will cause transmission to cease and will cause the remote sensing unit to go back from a data acquisition and transmission mode of operation into a power acquisition mode of operation. Then, when specified charge levels are obtained again, the data acquisition and transmission resumes.
As previously discussed, the signals transmitted by a power and communication signal transceiver system 3200 include communication signals superimposed with a high power carrier signal. The high power carrier signal being for delivering power to the remote sensing unit to allow the remote sensing unit to charge an internal capacitor to provide power for its internal circuitry.
Power supply 3304 also is connected to provide power to a demodulator 3312, to a modulator 3314, to logic device 3318, to data acquisition circuitry 3322 and to RF Oscillator 3328. The connections for conducting power to these devices are not shown herein for simplicity. As may be seen, power supply 3304 is coupled to antenna 3308 through a switch 3318.
Once the remote sensing unit has acquired the specified data or information, the remote sensing unit transmits communication signal back to the external source during time period 3422. As may be seen, once time period 3422 is expired, the external source resumes transmitting RF power for time period 3426. The termination of time period 3422 can be from one of several different situations. First, if the capacitor charge levels are reduced to specified charge levels, internal logic circuitry will cause the remote sensing unit to stop transmitting data and to go into a communication signal and RF power acquisition mode of operation so that the capacitor may be recharge. Once a remote sensing unit ceases transmitting communication signals, the external source resumes transmitting RF power and perhaps communication signals to the remote sensing unit so that it may recharge its capacitor.
A second reason that a remote sensing unit may cease transmitting thereby ending time period 3422 is that the external source may merely resume transmitting RF power. In this scenario, the remote sensing unit transitions into a communication signal and RF power acquisition mode of operation upon determining that the external source is transmitting RF power. Accordingly, there may actually be some overlap between time periods 3422 and the 3426.
A third reason a remote sensing unit may cease transmitting thereby ending timing period 3422 is that it has completed transmitting data it acquired during the data acquisition mode of operation. Finally, as may be seen, time periods 3430, 3434 and 3438 illustrate repeated transmission of control signals to the remote sensing unit, repeated data acquisition steps by the remote sensing unit, and repeated transmission of data by the remote sensing unit.
By way of example, the detected signature in the described embodiment is a gamma ray pip-tag signal emitted from a radioactive source within the remote sensing unit in addition to the radiation signals produced naturally in the subsurface formation. Thus, when the tool detects the signature, it transmits a signal to a ground based control unit indicating that the specified signature has been detected and that the tool is at the desired depth.
In the method illustrated herein, the well-bore can be either an open hole or a cased hole. The tool can be any known type of wireline tool modified to include transceiver circuitry and an antenna for communicating with a remote sensing unit. The tool can also be any known type of drilling tool including an MWD (measure while drilling tool). The primary requirement for the tool being that it preferably should be capable of transmitting and receiving wireless communication signals with a remote sensing unit and it preferably should be capable of transmitting an RF signal with sufficient strength to provide power to the remote sensing unit as will be described in greater detail below.
Once the tool has detected the specified signature, the tool position is adjusted to maximize the signature signal strength (step 3508). Presumably, maximum signal strength indicates that the position of the tool with relation to the remote sensing unit is optimal as described elsewhere herein.
Once the tool has been lowered to an optimal position, an RF power signal is transmitted from the tool to the remote sensing unit to cause to charge it capacitor and to "wake up" (step 3512). Typically, the transmitted signal must be of sufficient strength for 10 mW −50 mW of power to be delivered through inductive coupling to the remote sensing unit. By way of example, the RF signal might be transmitted for a period of one minute.
There are several different factors to consider that affect the amount of power that can be inductively delivered to the remote sensing unit. First, for formations having a resistivity ranging from 0.2 to 2000 ohms, a signal having a fixed frequency of 4.5 MHz typically is best for power transfer to the remote sensing unit. Accordingly, it is advantageous to transmit an RF signal that is substantially near the 4.5 MHz frequency range. In the preferred embodiment, the RF power is transmitted at a frequency of 2.0 MHz. The invention herein contemplates, however, transmitted RF power anywhere in the range of 1 MH to 50 MHz. This accounts for high-resistivity formations (>200 ohms), wherein the optimum RF transmission frequency would be greater than 4.5 MHz.
One reason that the described embodiment is operable to transmit the RF power at a 2.0 MHz frequency is that standard "off the shelf" equipment, for example, combined magnetic resonance systems and LWD resistivity tools, operate at the 2.0 MHz frequency. Additionally, a relatively simple antenna having only one or two coils is required to efficiently deliver power at the 2.0 MHz frequency. In contrast, a relatively complicated antenna structure must be used for RF transmissions in the 500 MHz frequency range. Also, at this frequency, power transfer is near optimum for low resistivity formations. As the transmission frequency is increased, efficiency in coupling is also increased. However, as the transmission frequency is increased, losses in the formation also increase, thereby limiting the distance at which data and power may be communicated to the remote sensor. At the transmission frequency of the embodiment, these factors are optimized to produce a maximum power transfer ratio.
In addition to transmitting RF power to the remote sensing unit, the tool also transmits control commands that are superimposed on the RF power signals (step 3516). One reason for superimposing the control commands and transmitting them while the RF power signal is being transmitted is simplicity and to reduce the required amount of time for communicating with and delivering power to the remote sensing unit. The control commands, in the described embodiment, merely indicate what formation parameters (e.g., temperature or pressure) are selected. As will be described below, the remote sensing unit then acquires sample measurements and transmits signals reflecting the measured samples responsive to the received control commands.
The control commands are superimposed on the RF power signal in a modulated format. While any known modulation scheme may be used, one that is used in the described embodiment is DPSK (differential phase shift keying). In DPSK modulation schemes, a phase shift is introduced into the carrier to represent a logic state. By way of example, the phase of a carrier frequency is shifted by 180° when transmitting a logic "1," and remains unchanged when transmitting a logic "0." Other modulation schemes that may be used include true amplitude modulation (AM), true frequency shift keying, pulse position and pulse width modulation.
Control signals are not always transmitted, however, while the RF power signals are being transmitted. Thus, only RF power is transmitted at times and, at other times, control signals superimposed upon the RF power signals are transmitted. Additionally, depending upon the charge levels of the remote sensing unit, only control signals may be transmitted during some periods.
Once RF power has been transmitted to the remote sensing unit for a specified amount of time, the tool ceases transmitting RF power and attempts to receive wireless communication signals from the remote sensing unit (step 3520). A typical specified amount of the time to wake up a remote sensing unit and to fully charge a charge storage device within the remote sensing unit is one minute. After RF power transmission are stopped, the tool continues to listen and receive communication signals until the remote sensing unit stops transmitting.
After the remote sensing unit stops transmitting, the tool transmits power signals for a second specified time period to recharge the capacitor within the remote sensing unit and then listens for additional transmissions from the remote sensing unit. A typical second period of time to charge the charge storage device within the remote sensing unit is significantly less than the first specified period of time that is required to "wake up" the remote sensing unit and to charge its capacitor. One reason is that a remote sensing unit stop transmitting to the tool whenever its charge is depleted by approximately 10 percent of being fully charged. Accordingly, to ensure that the charge on the capacitor is restored, a typical second specified period of time for transmitting RF power to the remote sensing unit is 15 seconds.
This process of charging and then listening is repeated until the communication signals transmitted by the remote sensing unit reflect data samples whose values are stable (step 3524). The reason the process is continued until stable data sample values are received is that it is likely that an awakened remote sensing unit may not initially transmit accurate data samples but that the samples will become accurate after some operation. It is understood that stable values means that the change of magnitude from one data sample to another is very small thereby indicating a constant reading within a specified error value.
Once the remote sensing unit has been "woken up" by the RF power being transmitted to it, the remote sensing unit begins sampling and storing data representative of measured subsurface formation characteristics (step 3612). In the described embodiment, the remote sensing unit takes samples responsive to received control signals from the well-bore tool. As described before, the received control signals are received in a modulated form superimposed on top of the RF power signals. Accordingly, the remote sensing unit must demodulate and interpret the control signals to know what types of samples it is being asked to take and to transmit back to the tool.
In an alternate embodiment, the remote sensing unit merely takes samples of all types of formation characteristics that it is designed to sample. For example, one remote sensing unit may be formed to only take pressure measurements while another is designed to take pressure and temperature. For this alternate embodiment, the remote sensing unit merely modulates and transmits whatever type of sample data it is designed to take. One advantage of this alternate embodiment is that remote sensing unit electronics may be simplified in that demodulation circuitry is no longer required. Tool circuitry is also simplified in that it no longer requires modulation circuitry and, more generally, the ability to transmit communication signals to the remote sensing unit.
Periodically, the remote sensing unit determines if the well-bore tool is still transmitting RF power (step 3616). If the remote sensing unit continues to receive RF power, it continues taking samples and storing data representative of the measured sample values while also charging the capacitor (or at least applying a DC voltage across the terminals of the capacitor) (step 3608). If the remote sensing unit determines that the well-bore tool is no longer transmitting RF power, the remote sensing unit modulates and transmits a data value representing a measured sample (step 3620). For example, the remote sensing unit may modulate and transmit a number reflective of a measured formation pressure or temperature.
The remote sensing unit continues to monitor the charge level of its capacitor (step 3624). In the described embodiment, internal logic circuitry periodically measures the charge. For example, the remaining charge is measured after each transmission of a measured subsurface formation sample data value. In an alternate embodiment, an internal switch changes state once the charge drops below a specified charge level.
If the charge level is above the specified charge level, the remote sensing unit determines if there are more stored sample data values to transmit (step 3628). If so, the remote sensing unit transmits the next stored sample data value (step 3632). Once it transmits the next stored sample data value, it again determines the capacitor charge value as described in step 3624. If there are no more stored sample data values, or if it determines in step 3624 that the charge has dropped below the specified value, the remote sensing unit stops transmitting (step 3636). Once the remote sensing unit stops transmitting, the well-bore tool determines whether more data samples are required and, if so, transmits RF power to fully recharge the capacitor of the remote sensing unit. This serves to start the process over again resulting in the remote sensing unit acquiring more subsurface formation samples.
While the described embodiment herein
In another example, one remote sensing unit includes only temperature measuring circuitry and equipment while the second remote sensing unit includes only pressure measuring circuitry and equipment. For simplicity sake, the network shown in
In the described embodiment, antenna 3716 includes a first and a second antenna section, each antenna section being characterized by a plane that is substantially perpendicular to a primary axis of the well-bore tool. Antenna 3712 is characterized by a plane that is substantially perpendicular to the planes of the first and second antenna sections of antenna 3716. Further, antenna 3716 is formed so that a current travels in circularly opposite directions in the first and second antenna sections relative to each other.
Antenna 3712 is coupled to remote sensing unit circuitry 3718, the circuitry 3718 including a power supply having a charge storage device for storing induced power, a tranceiver unit for receiving induced power signals and for transmitting data values, a sampling unit for taking subsurface formation samples and a logic unit for controlling the circuitry of the remote sensing unit.
The well-bore tool transceiver system includes transceiver circuitry 3706 and antenna 3716. In the described embodiment, well-bore tool transceiver circuitry is formed within the well-bore tool 3708. In an alternate embodiment, however, transceiver circuitry 3706 can be formed external to well-bore tool 3708.
First oilfield communication network 3704 is electrically coupled to a second oilfield communication network 3750 by way of cabling 3754 (wellbore communication link). Second oilfield communication network 3750 includes a well control unit 3758 that is connected to cabling 3754 and is therefore capable of sending and receiving communication signals to and from first oilfield communication network 3704. Well control unit 3758 includes transceiver circuitry 3762 that is connected to an antenna. The well control unit 3758 may also be capable of controlling production equipment for the well.
Second oilfield communication network 3750 further includes an oilfield control unit 3764 that includes transceiver circuitry that is connected to an antenna 3768. Accordingly, oilfield control unit 3764 is operable to communicate to receive data from well control unit 3758 and to transmit control commands to the well control unit 3758 over a communication link 3772.
Typical control commands transmitted from the oilfield control unit 3764 over communication link 3772, according to the present invention, include not only parameters that define production rates from the well, but also requests for subsurface formation data. By way of example, oilfield control unit 3764 may request pressure and temperature data for each of the formations of interest within the well controlled by well control unit 3758. In such a scenario, well control unit 3758 transmits signals reflecting the desired information to well-bore tool 3708 over cabling 3754. Upon receiving the request for information, the well-bore transceiver 3706 initiates the processes described herein to obtain the desired subsurface formation data.
The described embodiment of second oilfield communication network 3750 includes a base station transceiver system at the oilfield control unit 3764 and a fixed wireless local loop system at the well control unit 3758. Any type of wireless communication network, and any type of wired communication network is included herein as part of the invention. Accordingly, satellite, all types of cellular communication systems including, AMPS, TDMA, CDMA, etc., and older form of radio and radio phone technologies are included. Among wireline technologies, internet networks, copper and fiberoptic communication networks, coaxial cable networks and other known network types may be used to form communication link 3772 between well control unit 3758 and oilfield control unit 3764.
Once the first transceiver of the first network receives formation data, it transmits the formation data to a well control unit of a second oilfield network, the well control unit including a first transceiver of the second network (step 3820). Approximately at the time the well control unit receives or anticipates receiving formation data from the first network, a second communication link is established within the second oilfield network (step 3830). More specifically, the well control unit transceiver establishes a communication link with a central oilfield control unit transceiver. Establishing the second communication link allows formation data to be transmitted from the well control unit transceiver to the oilfield control unit (step 3832) and, optionally, control commands from the oilfield control unit (step 3834).
The method of
As will be readily apparent to those skilled in the art, the present invention may easily be produced in other specific forms without departing from its spirit or essential characteristics. The present embodiment is, therefore, to be considered as merely illustrative and not restrictive. The scope of the invention is indicated by the claims that follow rather than the foregoing description, and all changes which come within the meaning and range of equivalence of the claims are therefore intended to be embraced therein.
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