Patent Grant
7296462
Not Applicable.
Not Applicable.
During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations, such as monitoring the operability of equipment used during the drilling process or evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubblepoint, formation pressure gradient, mobility, filtrate viscosity, spherical mobility, coupled compressibility porosity, skin damage (which is an indication of how the mud filtrate has changed the permeability near the wellbore), and anisotropy (which is the ratio of the vertical and horizontal permeabilities). These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production.
Drill stem testers (DST) and wireline formation testers (WFT) have been commonly used to perform these tests. The basic DST tool consists of a packer or packers, valves, or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on a work string to the zone to be tested. The packer or packers are set, and drilling fluid is evacuated to isolate the zone from the drilling fluid column. The valves or ports are then opened to allow flow from the formation to the tool for testing while the recorders chart static pressures. A sampling chamber traps formation fluid at the end of the test. WFTs generally employ the same testing techniques but use a wireline to lower the test tool into the borehole after the drill string has been retrieved from the borehole. WFTs typically use packers also, although the packers are typically placed closer together, compared to DSTs, for more efficient formation testing. In some cases, packers are not even used. In those instances, the testing tool is brought into contact with the formation and testing is done without zonal isolation.
WFTs may also include a probe assembly for engaging the borehole wall and acquiring formation fluid samples. The probe assembly may include an isolation pad to engage the borehole wall. The isolation pad seals against the formation and around a hollow probe, which places an internal cavity in fluid communication with the formation. This creates a fluid pathway that allows formation fluid to flow between the formation and the formation tester while isolated from the borehole fluid.
With the use of DSTs and WFTs, the drill string with the drill bit must first be retracted from the borehole. Then, a separate work string containing the testing equipment, or, with WFTs, the wireline tool string, must be lowered into the well to conduct secondary operations.
DSTs and WFTs may also cause tool sticking or formation damage. There may also be difficulties of running WFTs in highly deviated and extended reach wells. WFTs also do not have flowbores for the flow of drilling mud, nor are they designed to withstand drilling loads such as torque and weight on bit.
Further, the formation pressure measurement accuracy of drill stem tests and, especially, of wireline formation tests may be affected by mud filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation after the borehole has been drilled. Mud filtrate invasion occurs when the drilling mud fluids displace formation fluid. Because the mud filtrate ingress into the formation begins at the borehole surface, it is most prevalent there and generally decreases further into the formation. When filtrate invasion occurs, it may become impossible to obtain a representative sample of formation fluid or, at a minimum, the duration of the sampling period must be increased to first remove the drilling fluid and then obtain a representative sample of formation fluid. Mudcake buildup occurs when any solid particles in the drilling fluid are plastered to the side of the wellbore by the circulating drilling mud during drilling. The prevalence of the mudcake at the borehole surface creates a “skin” that can affect the measurement results. The mudcake also acts as a region of reduced permeability adjacent to the borehole. Thus, once the mudcake forms, the accuracy of reservoir pressure measurements decreases, affecting the calculations for permeability and producibility of the formation. The mudcake should be flushed out of the formation before a true, uncontaminated sample of the fluid can be collected. Thus, it may be desirable to pump formation fluid that is contaminated with filtrate from the formation until uncontaminated connate fluid can be identified and produced.
Another testing apparatus is the formation tester while drilling (FTWD) tool. Typical FTWD formation testing equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are used for isolating a formation from the remainder of the borehole, drawing fluid from the formation, and measuring physical properties of the fluid and the formation. Fluid properties, among other items, may include fluid compressibility, flowline fluid compressibility, density, resistivity, composition, and bubblepoint. For example, the FTWD may use a probe similar to a WFT that extends to the formation and a small sample chamber to draw in formation fluid through the probe to test the formation pressure. To perform a test, the drill string is stopped from rotating and moving axially and the test procedure, similar to a WFT described above, is performed.
After the testing of a well, it may be desirable to leave the testing string in place in the well and stimulate or otherwise treat the various formations of the well by pumping acids and other fluids into the formations. Well stimulation refers to a variety of techniques used for increasing the rate at which fluids flow out of or into a well at a fixed pressure difference. As used herein, the terms “stimulate”, “stimulation”, etc. are used in relation to operations wherein it is desired to inject, or otherwise introduce, fluids into a formation or formations intersected by a wellbore of a subterranean well. Typically, the purpose of such stimulation operations is to increase a production rate and/or capacity of hydrocarbons from the formation or formations. For example, stimulation operations may include a procedure known as “fracturing” wherein fluid is injected into a formation under relatively high pressure in order to fracture the formation, thus making it easier for hydrocarbons within the formation to flow toward the wellbore. Other stimulation operations include acidizing, acid-fracing, etc. Well treatment may include injecting such fluids as anti-emulsion fluid, etc.
For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings:
In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be illustrated exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be illustrated in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are illustrated in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.
The tool 10 further comprises a pump 22. The pump 22 may be a centrifugal pump, a piston pump, or any other suitable type of fluid/gas pump. The pump 22 may also be a reversible pump such that flow through the pump 22 may be reversed without moving or changing the pump 22 itself. The pump 22 may be powered by any suitable means such as at least one of a power conduit through a wireline connection, downhole batteries, or a downhole generator.
As illustrated in
The tool 10 further comprises at least two interval access ports 24,26. The interval access ports 24,26 are located between the inflatable packers 12 and provide fluid communication between the tool 10 and the fluid within the packed-off interval annulus 18. Although only two interval access ports are illustrated, the tool 10 may comprise as many interval access ports 24,26 as appropriate for the operations of the tool 10.
Connecting the interval access ports 24,26 with the pump 22 is a fluid conduit system generally designated by numeral 28. The fluid conduit system 28 may comprise interval flowlines 30,32 to each interval access port 24,26. The fluid conduit system 28 may further comprise a packer flowline 34 providing fluid flow to each of the packers 12. The fluid conduit system 28 may further comprise a main flowline 36 connecting the interval flowlines 30,32 and the packer flowline 34 with the pump 22. The fluid conduit system 28 may further comprise a discharge line 38 that discharges fluid from the tool 10 to outside the packed-off annulus 18. Alternatively, the fluid in the discharge line 38 may be redirected with additional flowlines and valving to other tools or sections on the wireline or drillstring without being discharged to the borehole 19. The fluid conduit system 28 need not be configured exactly as illustrated in
Also within the fluid conduit system 28 are valves for controlling fluid flow within the fluid conduit system 28. As illustrated in
The tool 10 also further comprises a sensor 48 for measuring the pressure of the fluid within the interval access flowline 30 and a sensor 50 for measuring the pressure of the fluid within the packer flowline 34. The tool 10 may further comprise a sensor 52 for measuring additional properties of the fluid in the interval flowline 30. For example, the sensor 52 may measure fluid resistivity or fluid temperature. The sensor 52 may measure other properties of the fluid in the interval flowline 30 as well. Alternatively, although not illustrated, the fluid conduit system 28 may comprise a cross-over flowline and a cross-over valve directing fluid from the interval flowline 32 to the interval flowline 30 to be measured by the sensors 48,52. Also alternatively, the tool 10 may comprise additional sensors 48,52 on each of the interval flowlines 30,32.
As illustrated in
As illustrated in
As illustrated, the interval access port 24 may be positioned close to the top of the packed-off interval. As a result, the fluid pumped through interval access port 24 may be the “lighter”, or less dense, fluids from the interval annulus 18 such as gas or oil as opposed to water. However, the location of the interval access port 24 may vary depending on the configuration of the tool 10 and the density of the fluids pumped through the interval access port 24. Additionally, the variance of the density and resulting stratification of the fluids in the packed-off interval annulus 18 depends on the composition of the fluids in the particular packed-off interval annulus 18 at any given time.
As illustrated, the interval access port 26 may be positioned close to the bottom of the packed-off interval. As a result, the fluid pumped through interval access port 26 may be the “heavier”, or more dense, fluids from the interval annulus 18 such as oil or water as opposed to gas. However, the location of the interval access port 26 may vary depending on the configuration of the tool 10 and the density of the fluids pumped through the interval access port 26. Additionally, the variance of the density and resulting stratification of the fluids in the interval annulus 18 depends on the composition of the fluids in the particular interval annulus 18 at any given time.
As illustrated in
Alternatively, as illustrated in
With the outlet of the pump 22 set as shown by direction arrow B, the chamber valve 78 is opened and the discharge valve 82 is closed. Additionally, although not shown, a valve may close fluid flow through the main flowline 36 below the tool 10. The pump 22 is then started to pump well enhancement fluid from the fluid chamber 54, out of at least one of the interval access ports 24,26, and into the formation interval annulus 18. The pump 22 may then be stopped and the pressure of the fluid in at least one of the interval flowlines 30,32 may be monitored by sensor 48 or multiple sensors 48 in one or each of the interval flowlines 30,32 as described above. The sensor(s) 52 may also monitor other fluid properties in one or each of the interval flowlines 30,32 as described above. Alternatively, there may be more than one fluid chamber 54 and more than one pump 22 for pumping fluid into the packed-off interval annulus 18. The fluid chamber 54 may also be releasably connected to the downhole tool 10 for the retrieval of collected fluids. After fluid is collected into the chamber 54, the chamber 54 may be closed and released from the tool 10 into the borehole 19 above the packed-off interval annulus 18. The fluid chamber 54 may then be pumped by fluid in the borehole to the surface.
Alternatively, as illustrated in
With the outlet of the pump 22 set as shown by direction arrow B, the chamber valves 78,80 are opened, the discharge valves 82,86 are closed, and the main flowline valve 46 is closed. Additionally, although not shown, a valve may close fluid flow through the main flowline 36 below the tool 10. The pump 22 is started to pump well enhancement fluid from the fluid chamber 54, out of the interval access port 24, and into the formation interval annulus 18. The well enhancement fluid then flows “though” the packed-off interval annulus 18 and into the interval access port 26 where it then flows into the fluid chamber 56. The pump 22 may then be stopped and the pressure of the fluid in at least one of the interval flowlines 30,32 may be monitored by sensor 48 or multiple sensors 48 in one or each of the interval flowlines 30,32 as described above. The sensor(s) 52 may also monitor other fluid properties in one or each of the interval flowlines 30,32 as described above.
Additionally, the outlet of the pump 22 may be reversed to flow as illustrated by direction arrow C. The pump 22 is started to pump well enhancement fluid from the fluid chamber 56, out of the interval access port 26, and into the formation interval annulus 18. The well enhancement fluid then flows “though” the packed-off interval annulus 18 and into the interval access port 24 where it then flows back into the fluid chamber 54. The pump 22 may then be stopped and the pressure of the fluid in at least one of the interval flowlines 30,32 may be monitored by sensor 48 or multiple sensors 48 in one or each of the interval flowlines 30,32 as described above. The sensor(s) 52 may also monitor other fluid properties in one or each of the interval flowlines 30,32 as described above.
The reversible “flow through” process described above may be repeated as many times as desired. Alternatively, the tool 10 may comprise any number of the fluid chambers 54,56 with the fluid chambers 54,56 containing the same or different well enhancement fluids. Also, the tool 10 may comprise additional pumps 22 pumping fluid through the additional fluid chambers 54,56. At least one of the fluid chambers 54,56 may also be releasably connected to the downhole tool 10 for the retrieval of collected fluids. After fluid is collected into the chamber 54 and/or 56, the chamber 54 and/or 56 may be closed and released from the tool 10 into the borehole 19 above the packed-off interval annulus 18. The fluid chamber 54 and/or 56 may then be pumped by fluid in the borehole 19 to the surface.
With respect to all of the embodiments described, the sensors 48,50,52 may collect data on the operation of the tool 10, the annulus fluid, and/or the well enhancement fluid. This data may be stored locally within the tool 10 for retrieval once the tool 10 is removed from the borehole 19. Additionally or alternatively, all of the embodiments of the tool 10 may incorporate the use of at least one writeable and readable data storage unit, or data carrier 88, capable of flow within the borehole annulus from the tool 10 to the surface.
The at least one data carrier 88 is a data storage device that can be directly or remotely written to and read. The data carrier 88 preferably comprises a circuit including a data chip and an antenna encapsulated to protect circuit from the fluid flow. A suitable data carrier may be similar in construction to commercially available non-contact identification transponders, for example the AVID identity tags or AVID industrial RFID transponders available from AVID. These identity tags and transponders may comprise an integrated circuit and coil capacitor hermetically sealed in biocompatible glass. For example, the identity tags and transponders may only be 0.45 inches by 0.08 inches, weigh approximately 0.0021 oz., and carry 96 bits. The tag may not have an internal power source, and instead be powered by RF energy from a reader, which generates a 125 KHz radio signal. When the tag is within the electromagnetic field of the reader, the tag transmits its encoded data to the reader, where it can be decoded and stored. Typical read distances range from 4.125 inches (10 cm) to about 10.25 inches (26 cm), and read times are less than 40 msec. The data carrier 88 may also be any other suitable type of data storage device that can be directly or remotely written to and read.
The tool 10 also includes at least one writing device 90 for writing to the data carriers 88. The writing device 90 may directly write to the data carriers 88 or may be a remote writing device that remotely writes data to the data carriers 88. The data carriers 88 also interact with a reading device 92 for reading the data carriers 88. The reading device 92 may directly read the data from the data carriers 88 or may be a remote reading device for remotely reading the data carriers 88 as they pass the reading device 92.
The data written on the data carriers 88 may also include ordering or sequencing data as well as information data, so that the information data can be properly reassembled. Because spacing between the data carriers 88 can vary, and in fact the data carriers 88 can arrive at the reading device 92 out of sequence, the ordering or sequencing information allows the data to be reassembled correctly. The data may also be redundantly written on at least two data carriers 88, to reduce the risk of lost data if some data carriers 88 become lost or damaged.
At least one data carrier 88 is circulated in the annulus fluid. Data may be written to the at least one data carrier 88 directly or remotely as described above with data from at least one of the sensors 48,50,52. Other downhole sensors may also write data to the at least one data carrier 88. For example, data related to formation pressure, porosity, and resistivity may be collected and written to the at least one data carrier 88. There may also be more than one data carrier 88 for transporting data from the sensors 48,50,52. The process of writing data may clear the memory of the data carrier 88, or a separate eraser 116 may be provided to clear previously recorded data. The at least one data carrier 88 may then be placed in the fluid conduit system 28 of the tool 10 and pumped out of the discharge line 38 into the annulus above the tool 10 in the borehole 19. The at least one data carrier 88 then flows with the drilling fluid back up the borehole 19 in the space surrounding the drilling string 102. At the top of the well the fluid is drawn off in a conduit 118. A data reader 120 may then read the data from the at least one data carrier 88. There may also be a data eraser 122 provided to erase the at least one data carrier 88 as it or they flow in the fluid through the conduit 118. A separator or shaker table 124 can collect the at least one data carrier 88 from the fluid for reuse.
The drilling rig 100 may also be configured for two way communication so that in addition to permitting information about the underground conditions to be communicated to the surface, instructions from the surface can be communicated to the tool 10. A data writer 126 can be provided at the surface for writing data to at least one data carrier 88 either before the at least one carrier 88 is introduced into the borehole fluid or after the at least one data carrier 88 is introduced into the fluid. The tool 10 would then also be provided with a data reader 128 to read the data on the at least one data carrier 88 as it or they reach the tool 10.
While specific embodiments have been illustrated and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
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|---|---|---|---|
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| Number | Date | Country | |
|---|---|---|---|
| 20060248949 A1 | Nov 2006 | US |
