Patent Application
20070158062
Subsurface wells for extracting and/or testing fluid (liquid or gas) samples on land and at sea have been used for many years. Many structures have been developed in an attempt to isolate the fluid from a particular depth in a well so that more accurate in situ or remote laboratory testing of the fluid at that depth “below ground surface” (bgs) can be performed. Unfortunately, attempts to accurately and cost-effectively accomplish this objective have been not altogether satisfactory.
For example, typical wells include riser pipes have relatively large diameters, i.e. 2-4 inches, or greater. Many such wells can have depths that extend hundreds or even thousands of feet bgs. In order to accurately remove a fluid sample from a particular target zone within a well, such as a sample at 1,000 feet bgs, typical wells require that the fluid above the target zone be removed at least once, and more commonly 3 to 5 times this volume, in order to obtain a more representative fluid sample from the desired level. From a volumetric standpoint, traditional wet casing volumes of 2-inch and 4-inch monitoring wells are 0.63 liters (630 ml) to 2.5 liters (2,500 ml) per foot, respectively. As an example, to obtain a sample at 1,000 feet bgs, approximately 630 liters to 2,500 liters of fluid must be purged from the well at least once and more commonly as many as 3 to 5 times this volume. The time required and costs associated with extracting this fluid from the Well can be rather significant.
One method of purging fluid from the well and/or obtaining a fluid sample includes using coaxial gas displacement within the riser pipe of the well. Unfortunately, this method can have several drawbacks. First, gas consumption during pressurization of these types of systems can be relatively substantial because of the relatively large diameter and length of riser pipe that must be pressurized. Second, introducing large volumes of gas into the riser pipe can potentially have adverse effects on the volatile organic compounds (VOC's) being measured in the fluid sample that is not collected properly. Third, a pressure sensor that may be present within the riser pipe of a typical well is subjected to repeated pressure changes from the coaxial gas displacement pressurization of the riser pipe. Over time, this artificially-created range of pressures in the riser pipe may have a negative impact on the accuracy of the pressure measurements from the sensor. Fourth, residual gas pressure can potentially damage one or more sensors and/or alter readings from the sensors once substantially all of the fluid has passed through the sample collection line past the sensors. Fifth, any leaks in the system can cause gas to be forcibly infused into the ground formation, which can influence the results of future sample collections.
Another method for purging fluid from these types of wells includes the use of a bladder pump. Bladder pumps include a bladder that alternatingly fills and empties with a gas to force movement of the fluid within a pump system. However, the bladders inside these pumps can be susceptible to leakage due to becoming fatigued or detached during pressurization. Further, the initial cost as well as maintenance and repair of bladder pumps can be relatively expensive. In addition, at certain depths, bladder pumps require an equilibration period during pressurization to decrease the likelihood of damage to or failure of the pump system. This equilibration period can result in a slower overall purging process, which decreases efficiency.
An additional method for purging fluid from a well includes using an electric submersible pump system having an electric motor. This type of system can be susceptible to electrical shorts and/or burning out of the electric motor. Additionally, this type of pump typically uses one or more impellers that can cause pressure differentials (e.g., drops), which can result in VOC loss from the sample being collected. Operation of these types of electric pumps can also raise the temperature of the groundwater, which can also impact VOC loss. Moreover, these pumps can be relatively costly and somewhat more difficult to repair and maintain.
Further, the means for physically isolating a particular zone of the well from the rest of the well can have several shortcomings. For instance, inflatable packers are commonly used to isolate the fluid from a particular zone either above or below the packer. However, these types of packers can be subject to leakage, and can be cumbersome and relatively expensive. In addition, these packers are susceptible to rupturing, which potentially damage the well.
The present invention is directed toward a zone isolation assembly for a subsurface well that extends downward from a surface region. The subsurface well includes (i) a first fluid inlet structure that at least partially defines a first zone that receives a first fluid, and (ii) a second zone that is nearer to the surface region than the first zone. In one embodiment, the zone isolation assembly includes a fixed docking receiver and a docking apparatus. The docking receiver is coupled to the first fluid inlet structure. Further, the docking receiver at least partially defines the first zone. In this embodiment, the docking apparatus is selectively moved relative to the docking receiver between a disengaged position and an engaged position. In the disengaged position, the first zone is in fluid communication with the second zone. In the engaged position, the docking apparatus engages the docking receiver so that the first zone is not substantially in fluid communication with, or is completely isolated from, the second zone during movement of the first fluid between the first zone and the surface region. The docking apparatus can include a resilient seal that forms a substantially fluid-tight seal with the docking receiver when the docking apparatus is in the engaged position.
In certain embodiments, the docking apparatus is maintained in the engaged position substantially by a force of gravity. In alternative embodiments, the zone isolation assembly can also include a pump assembly that is coupled to the docking apparatus. The pump assembly can pump the first fluid out of the first zone while the docking apparatus is in the engaged position. In some embodiments, the pump assembly is positioned substantially within the first zone while the docking apparatus is in the engaged position. Alternatively, the pump assembly can be positioned substantially within the second zone while the docking apparatus is in the engaged position. Further, the subsurface well includes a riser pipe that at least partially defines the second zone. In certain embodiments, the pump assembly is removable from the riser pipe. In one embodiment, the subsurface well includes a gas inlet line that guides movement of a gas to the pump assembly, and a fluid outlet line that guides movement of the first fluid toward the surface region. In this embodiment, the gas does not contact the first fluid while the first fluid is in the fluid outlet line.
In certain embodiments, the zone isolation assembly can include a fluid collector that is coupled to the docking apparatus. The fluid collector can collect the first fluid for transport to the surface region. In some embodiments, the fluid collector is positioned within the first zone during collection of the portion of the first fluid. The fluid collector can include a perforated sipping tube, a passive diffusion sampling apparatus, or a pressurizable bailer, as non-exclusive examples.
In some embodiments, the zone isolation assembly can also include a substantially fluid-tight manifold that selectively inhibits a fluid from entering into the second zone through the surface region.
In another embodiment, the zone isolation assembly can include a fluid disperser that is at least partially positioned in the first zone. In this embodiment, the fluid disperser can disperse a dispersion fluid (such as a remediation or tracer fluid) from the surface region into the first zone while the docking apparatus is in the engaged position.
The subsurface well can also include a second fluid inlet structure that allows a second fluid to enter the second zone without contacting the first fluid when the docking apparatus is in the engaged position.
The present invention is also directed toward a fluid monitoring system including the zone isolation assembly and a fluid property sensor. The fluid property sensor can sense one or more fluid properties, including electrical properties, optical properties, acoustical properties, chemical properties and/or hydraulic properties.
The novel features of this invention, as well as the invention itself, both as to its structure and its operation, will be best understood from the accompanying drawings, taken in conjunction with the accompanying description, in which similar reference characters refer to similar parts, and in which:
Monitoring the fluid in accordance with the present invention can be performed in situ or following removal of the fluid from its native or manmade environment 11. As used herein, the term “monitoring” can include a one-time measurement of a single parameter of the fluid, multiple or ongoing measurements of a single parameter of the fluid, a one-time measurement of multiple parameters of the fluid, or multiple or ongoing measurements of multiple parameters of the fluid. Further, it is recognized that subsurface fluid can be in the form of a liquid and/or a gas. In addition, the Figures provided herein are not to scale given the extreme heights of the fluid monitoring systems relative to their widths.
The fluid monitoring system 10 illustrated in
The subsurface well 12 can be installed using any one of a number of methods known to those skilled in the art. In non-exclusive, alternative examples, the well 12 can be installed with hollow stem auger, sonic, air rotary casing hammer, dual wall percussion, dual tube, rotary drilling, vibratory direct push, cone penetrometer, cryogenic, ultrasonic and/or laser methods, or any other suitable method known to those skilled in the art of drilling and/or well placement. The wells 12 described herein include a surface region 32 and a subsurface region 34. The surface region 32 is an area that includes the top of the well 12 which extends to a surface 36. Stated another way, the surface region 32 includes the portion of the well 12 that extends between the surface 36 and the top of the riser pipe 30, whether the top of the riser pipe 30 is positioned above or below the surface 36. The surface 36 can either be a ground surface or the surface of a body of water or other liquid, as non-exclusive examples. The subsurface region 34 is the portion of the well 12 that is below the surface region 32, e.g., at a greater depth than the surface region 34.
The annular materials 24A-C can include a first layer 24A (illustrated by dots) that is positioned at or near the first zone 26, and a second layer 24B (illustrated by dashes) that is positioned at or near the second zone 28. The annular materials are typically positioned in layers 24A-C during installation of the well 12. It is recognized that although three layers 24A-C are included in the embodiment illustrated in
In one embodiment, for example, the first layer 24A can be sand or any other suitably permeable material that allows fluid to move from the surrounding ground environment 11 to the fluid inlet structure 29 of the well 12. The second layer 24B is positioned above the first layer 24A. The second layer 24B can be formed from a relatively impermeable layer that inhibits migration of fluid from the environment 11 near the fluid inlet structure 29 and the first zone 26 to the riser pipe 30 and the second zone 28. For example, the second layer 24B can include a bentonite material or any other suitable material of relative impermeability. In this embodiment, the second layer 28 helps increase the likelihood that the fluid collected through the fluid inlet structure 29 of the well 12 is more representative of the fluid from the environment 11 adjacent to the fluid inlet structure 29. The third layer 24C is positioned above the second layer 24B and can be formed from any suitable material, such as backfilled grout, bentonite, volclay and/or native soil, as one non-exclusive example. The third layer 24C is positioned away from the first layer 24A to the extent that the likelihood of fluid migrating from the environment 11 near the third layer 24C down to the fluid inlet structure 29 is reduced or prevented.
As used herein, the first zone 26 is a target zone from which a particular fluid sample is desired to be taken and/or monitored. Further, the second zone 28 can include fluid that is desired to be excluded from the fluid sample to be removed from the well 12 and/or tested, and is adjacent to the first zone 26. In the embodiments provided herein, the first zone 26 is positioned either directly beneath or at an angle below the second zone 28 such that the first zone 26 is further from the surface 36 of the surface region 32 than the second zone 28.
In each well 12, the first zone 26 has a first volume and the second zone 28 has a second volume. In certain embodiments, the second volume is substantially greater than the first volume because the height of the second zone 28 can be substantially greater than a height of the first zone 26. For example, the height of the first zone 26 can be on the order of between several inches to five or ten feet. In contrast, the height of the second zone 28 can be from several feet up to several hundreds or thousands of feet. Assuming somewhat similar inner dimensions of the first zone 26 and the second zone 28, the second volume can be from 100% to 100,000% greater than the first volume. As one non-exclusive example, in a 1-inch inner diameter well 12 having a depth of 1,000 feet, with the first zone 26 positioned at the bottom of the well 12, the first zone having a height of approximately five feet, the second zone 28 would have a height of approximately 995 feet. Thus, the first volume would be approximately 47 in3, while the second volume would be approximately 9,378 in3, or approximately 19,800% greater than the first volume.
For ease in understanding, the first zone 26 includes a first fluid 38 (illustrated with X's), and the second zone 28 includes a second fluid 40 (illustrated with O's). The first fluid 38 and the second fluid 40 migrate as a single fluid to the well 12 through the environment 11 outside of the fluid inlet structure 29. In this embodiment, a well fluid level 42W in the well 12 is the top of the second fluid 40, which, at equilibrium, is approximately equal to an environmental fluid level 42E in the environment 11, although it is acknowledged that some differences between the well fluid level 42W and the environmental fluid level 42E can occur. During equilibration of the fluid levels 42W, 42E, the fluid rises in the first zone 26 and the second zone 28 of the well 12. Due to gravitational forces and/or other influences, the fluid near an upper portion (e.g., in the second zone 28) of the well 12 will have a different composition from the fluid near a lower portion (e.g., in the first zone 26) of the well 12. Thus, although the first fluid 38 and the second fluid 40 can originate from a somewhat similar location within the environment 11, the first fluid 38 and the second fluid 40 can ultimately have different compositions at a point in time after entering the well 12, based on the relative positions of the fluids 38, 40 within the well 12.
The first fluid 38 is the liquid or gas that is desired for monitoring and/or testing. In this and other embodiments, it is desirable to inhibit mixing or otherwise commingling of the first fluid 38 and the second fluid 40 before monitoring and/or testing the first fluid 38. As described in greater detail below, the first fluid 38 and the second fluid 40 can be effectively isolated from one another utilizing the zone isolation assembly 22.
The fluid inlet structure 29 allows fluid from the first layer 24A outside the first zone 26 to migrate into the first zone 26. The design of the fluid inlet structure 29 can vary. For example, the fluid inlet structure 29 can have a substantially tubular configuration or another suitable geometry. Further, the fluid inlet structure 29 can be perforated, slotted, screened or can have some other alternative openings or pores (not shown) that allow fluid and/or various particulates to enter into the first zone 26. The fluid inlet structure 29 can include an end cap 31 at the lowermost end of the fluid inlet structure 29 that inhibits material from the first layer 24A from entering the first zone 26.
The fluid inlet structure 29 has a length 43 that can vary depending upon the design requirements of the well 12 and the subsurface monitoring system 10. For example, the length 43 of the fluid inlet structure 29 can be from a few inches to several feet or more.
The riser pipe 30 is a hollow, cylindrically-shaped structure. The riser pipe 30 can be formed from any suitable materials. In one non-exclusive embodiment, the riser pipe 30 can be formed from a polyvinylchloride (PVC) material and can be any desired thickness, such as Schedule 80, Schedule 40, etc. Alternatively, the riser pipe 30 can be formed from other plastics, fiberglass, ceramic, metal, etc. The length (oriented substantially vertically in
The inner diameter 44 of the riser pipe 30 can vary depending upon the design requirements of the well 12 and the fluid monitoring system 10. In one embodiment, the inner diameter 44 of the riser pipe 30 is less than approximately 2.0 inches. For example, the inner diameter 44 of the riser pipe 30 can be approximately 1.85 inches. In non-exclusive alternative embodiments, the inner diameter 44 of the riser pipe 30 can be approximately 1.40 inches, 0.90 inches, 0.68 inches, or any other suitable dimension. In still other embodiments, the inner diameter 44 of the riser pipe 30 can be greater than 2.0 inches.
The gas source 14 includes a gas 46 (illustrated with small triangles) that is used to move the first fluid 38 as provided in greater detail below. The gas 46 used can vary. For example, the gas 46 can include nitrogen, argon, oxygen, helium, air, hydrogen, or any other suitable gas. In one embodiment, the flow of the gas 46 can be regulated by the controller 17, which can be manually or automatically operated and controlled, as needed.
The gas inlet line 16 is a substantially tubular line that directs the gas 46 to the well 12 or to various structures and/or locations within the well 12, as described in greater detail below.
The controller 17 can control or regulate various processes related to fluid monitoring. For example, the controller 17 can adjust and/or control timing of the gas delivery to various structures within the well 12. Additionally, or alternatively, the controller 17 can adjust and/or regulate the volume of gas 46 that is delivered to the various structures within the well 12. In one embodiment, the controller 17 can include a computerized system. It is recognized that the positioning of the controller 17 within the fluid monitoring system 10 can be varied depending upon the specific processes being controlled by the controller 17. In other words, the positioning of the controller 17 illustrated in
The fluid receiver 18 receives the first fluid 38 from the first zone 26 of the well 12. Once received, the first fluid 38 can be monitored and/or tested by methods known by those skilled in the art. Alternatively, the first fluid 38 can be monitored and/or tested prior to being received by the fluid receiver 18. The first fluid 38 is transferred to the fluid receiver 18 via the fluid outlet line 20. Alternatively, the fluid receiver 18 can receive a different fluid from another portion of the well 12.
The zone isolation assembly 22 selectively isolates the first fluid 38 in the first zone 26 from the second fluid 40 in the second zone 28. The design of the zone isolation assembly 22 can vary to suit the design requirements of the well 12 and the fluid monitoring system 10. In the embodiment illustrated in
In the embodiment illustrated in
In certain embodiments, the docking receiver 48 is at least partially positioned at the uppermost portion of the first zone 26. In other words, a portion of the first zone 26 is at least partially bounded by the docking receiver 48. Further, the docking receiver 48 can also be positioned at the lowermost portion of the second zone 28. In this embodiment, a portion of the second zone 28 is at least partially bounded by the docking receiver 48.
The docking apparatus 50 selectively docks with the docking receiver 48 to form a substantially fluid-tight seal between the docking apparatus 50 and the docking receiver 48. The design and configuration of the docking apparatus 50 as provided herein can be varied to suit the design requirements of the docking receiver 48. In various embodiments, the docking apparatus 50 moves from a disengaged position wherein the docking apparatus 50 is not docked with the docking receiver 48, to an engaged position wherein the docking apparatus 50 is docked with the docking receiver 48.
In the disengaged position, the first fluid 38 and the second fluid 40 are not isolated from one another. In other words, the first zone 26 and the second zone 28 are in fluid communication with one another. In the engaged position (illustrated in
The docking apparatus 50 includes a docking weight 56, a resilient seal 58 and a fluid channel 60. In various embodiments, the docking weight 56 has a specific gravity that is greater than water. In non-exclusive alternative embodiments, the docking weight 56 can be formed from materials so that the docking apparatus has an overall specific gravity that is at least approximately 1.50, 2.00, 2.50, 3.00, or 4.00. In certain embodiments, the docking weight 56 can be formed from materials such as metal, ceramic, epoxy resin, rubber, nylon, Teflon, Nitrile, Viton, glass, plastic or other suitable materials having the desired specific gravity characteristics.
In various embodiments, the resilient seal 58 is positioned around a circumference of the docking weight 56. The resilient seal 58 can be formed from any resilient material such as rubber, urethane or other plastics, certain epoxies, or any other material that can form a substantially fluid-tight seal with the docking receiver 48. In one non-exclusive embodiment, for example, the resilient seal 58 is a rubberized O-ring. In this embodiment, because the resilient seal 58 is in the form of an O-ring, a relatively small surface area of contact between the resilient seal 58 and the docking receiver 48 occurs. As a result, a higher force in pounds per square inch (psi) is achieved. For example, a fluid-tight seal between the docking receiver 48 and the resilient seal 58 can be achieved with a force that is less than approximately 1.00 psi. In non-exclusive alternative embodiments, the force can be less than approximately 0.75, 0.50, 0.40 or 0.33 psi. Alternatively, the force can be greater than 1.00 psi or less than 0.33 psi.
The fluid channel 60 can be a channel or other type of conduit for the first fluid 38 to move through the docking weight 56, in a direction from the fluid collector 52 toward the pump assembly 54. In one embodiment, the fluid channel 60 can be tubular and can have a substantially circular cross-section. Alternatively, the fluid channel 60 can have another suitable configuration. The positioning of the fluid channel 60 within the docking weight 56 can vary. In one embodiment, the fluid channel 60 can be generally centrally positioned within the docking weight 56 so that the first fluid 38 flows substantially centrally through the docking weight 56. Alternatively, the fluid channel 60 can be positioned in an off-center manner. In certain embodiments, the fluid channel 60 effectively extends from the docking weight 56 to the pump assembly 54.
The docking apparatus 50 can be lowered into the well 12 from the surface region 32. In certain embodiments, the docking apparatus 50 utilizes the force of gravity to move down the riser pipe 30, through any fluid present in the riser pipe 30 and into the engaged position with the docking receiver 48. Alternatively, the docking apparatus 50 can be forced down the riser pipe 30 and into the engaged position by another suitable means.
The docking apparatus 50 is moved from the engaged position to the disengaged position by exerting a force on the docking apparatus 50 against the force of gravity, such as by pulling in a substantially upward manner, e.g., in a direction from the docking receiver 48 toward the surface region 32, on a tether or other suitable line coupled to the docking apparatus 50 to break or otherwise disrupt the seal between the resilient seal 58 and the docking receiver 48.
The fluid collector 52 collects the first fluid 38 from the first zone 26 for transport of the first fluid 38 toward the surface region 32. The design of the fluid collector 52 can vary depending upon the requirements of the subsurface monitoring system 10. In the embodiment illustrated in
The fluid collector 52 has a length 62 that can be varied to suit the design requirements of the first zone 26 and the fluid monitoring system 10. In certain embodiments, the fluid collector 52 extends substantially the entire length 43 of the fluid inlet structure 29. Alternatively, the length 62 of the fluid collector 52 can be any suitable percentage of the length 43 of the fluid inlet structure 29.
The pump assembly 54 pumps the first fluid 38 that enters the pump assembly 54 to the fluid receiver 18 via the fluid outlet line 20. The design and positioning of the pump assembly 54 can vary. In one embodiment, the pump assembly 54 is a highly robust, miniaturized low flow pump that can easily fit into a relatively small diameter wells 12, such as a 1-inch or ¾-inch riser pipe 30, although the pump assembly 54 is also adaptable to be used in larger diameter wells 12.
In the embodiment illustrated in
As explained in greater detail below, gas 46 from the gas source 14 is delivered down the gas inlet line 16 to the pump assembly 54 to force the first fluid 38 that has migrated to the pump assembly 54 during equilibration upward through the fluid outlet line 20 to the fluid receiver 18. With this design, the gas 46 does not cause any pressurization of the riser pipe 30, nor does the gas 46 utilize the riser pipe 30 during the pumping process. Stated another way, in this and other embodiments, the riser pipe 30 does not form any portion of the pump assembly 54. With this design, the need for high-pressure riser pipe 30 is reduced or eliminated. Further, gas consumption is greatly reduced because the riser pipe 30, which has a relatively large volume, need not be pressurized.
The pump assembly 54 can be coupled to the docking apparatus 50 so that removal of the docking apparatus 50 from the well 12 likewise results in simultaneous removal of the pump assembly 54 (and the fluid collector 52) from the well 12.
In an alternative embodiment, the pump assembly 54 can be incorporated as part of the docking apparatus 50 within a single structure. In this embodiment, the docking apparatus 50 can house the pump assembly 54, thereby obviating the need for two separate structures (docking apparatus 50 and pump assembly 54) that are illustrated in
In operation, following installation of the well 12, fluid from the environment enters the first zone 26 through the fluid inlet structure 29. Before the docking apparatus 50 is in the engaged position, the first zone 26 and the second zone 28 are in fluid communication with one another, thereby allowing the fluid to flow upwards and mix into the second zone while the fluid level is equilibrating within the well 12.
During a monitoring, sampling or testing process, the docking apparatus 50 is lowered into the well 12 down the riser pipe 30 until the docking apparatus 50 engages with the docking receiver 48. The resilient seal 58 forms a fluid-tight seal with the docking receiver 48 so that the first zone 26 and the second zone 28 are no longer in fluid communication with one another. At this point the fluid within the well becomes separated into the first fluid 38 and the second fluid 40.
In the embodiment illustrated in
The controller 17 (or an operator of the system) can commence the flow of gas 46 to the pump assembly 54 to begin pumping the first fluid 38 through the fluid outlet line 20 to the fluid receiver 18, as described in greater detail below. Once the first fluid 38 has been substantially purged from the first zone 26, the controller 17 can stop the flow of gas 46, which effectively stops the pumping process. The first zone 26 can then refill with more fluid from the environment 11, which can then be monitored, analyzed and/or removed for further testing as needed. Alternatively, the process of purging the fluid can be immediately followed by sampling the fluid 38, with the controller 17 being in continuous operation.
Because the volume of the first zone 26 is relatively small in comparison with the volume of the second zone 28, purging of the first fluid 38 from the first zone 26 occurs relatively rapidly. Further, because the first zone 26 is the sampling zone from which the first fluid 38 is collected, there is no need to purge or otherwise remove any of the second fluid 40 from the second zone 28. As long as the docking apparatus 50 remains in the engaged position, any fluid entering the first zone 26 will not be substantially influenced by or diluted with the second fluid 40.
The fluid inlet structure 229 has an outer diameter 264, the riser pipe 230 has an outer diameter 266, and the docking receiver 248 has an outer diameter 268. In this embodiment, the outer diameters 264, 266, 268 are substantially similar so that the outer casing of the well 212 has a standard form factor and is relatively uniform for easier installation. Alternatively, the outer diameters 264, 266, 268 can be different from one another.
In one embodiment, the resilient seal 358A can be an O-ring. For example, the O-ring can be formed from a compressible material such as rubber, Viton, Nitrile, Teflon, plastic, epoxy, or any other suitable material that is compatible with the docking receiver 348A for forming a fluid-tight seal to maintain fluid isolation between the first zone 326A and the second zone 328A. Alternatively, the resilient seal 358A can have another suitable configuration that is different than an O-ring.
Because of the relatively small surface area of the O-ring or other similar resilient seal 358A that is in contact with the docking receiver 348A when the docking apparatus 350A is in the engaged position, and the relatively high specific gravity of the docking weight 356A, a higher force in terms of pounds per square inch (psi) is achieved between the resilient seal 358A and the docking receiver 348A. As a result, the likelihood of achieving a fluid-tight seal is increased or achieved, and the likelihood of fluid leakage between the docking receiver 348A and the docking apparatus 350A is reduced or eliminated. Additionally, because of the relatively high force between the resilient seal 358A and the docking receiver 348A, in various embodiments, the resilient seal 358A is not inflatable. In these embodiments, the force of gravity is substantial enough to maintain the required fluid-tight seal and maintain the docking apparatus 350A in the engaged position.
Further, in the embodiment illustrated in
The intermediate section 374A has an inner diameter 378A near the location of contact between the resilient seal 358A and the docking receiver 348A that is smaller than an inner diameter 380A of the lower section 376A. Stated another way, the inner diameter 378A of the intermediate section 374A increases moving in a direction from the point of contact between the resilient seal 358A toward the lower section 376A. With this design, the first zone 326A can hold a greater volume of the first fluid 38 (illustrated in
The intermediate section 374C has an inner diameter 378C near the location of contact between the resilient seal 358C and the docking receiver 348C that is smaller than an inner diameter 382C of the upper section 372C. Further, the inner diameter 380C of the lower section 376C is somewhat reduced, and is substantially similar to the inner diameter 378C of the intermediate section 376C near the location of contact between the resilient seal 358C and the docking receiver 348C. In this embodiment, the lower section 376C of the interior surface 371C is substantially parallel with the exterior surface 370C. The reduced inner diameter 380C of the lower section 376C provides a smaller volume in the first zone 326C. Because the first zone 326C has a somewhat smaller volume, the volume of the first fluid to be purged from the first zone 326C is reduced, thereby decreasing the purge time prior to sampling the first zone 326C.
The specific design of the pump assembly 554 can vary. In this embodiment, the pump assembly 554 is a two-valve, two-line assembly. The pump assembly 554 includes a pump chamber 584, a first valve 582F, a second valve 582S, a portion of the gas inlet line 516 and a portion of the fluid outlet line 520. The pump chamber 584 can encircle one or more of the valves 582F, 582S and/or portions of the lines 516, 520.
The first valve 582F is a one-way valve that allows the first fluid (represented by arrow 538) to migrate or otherwise be transported from the first zone 26 into the pump housing 584. For example, the first valve 582F can be a check valve or any other suitable type of one-way valve that is open as the well fluid level 42W (illustrated in
The second valve 582S can also be a one-way valve that operates by opening to allow the first fluid 538 into the fluid outlet line 520 as the level of the first fluid 538 rises within the pump chamber 584 due to the equilibration process described previously. However, any back pressure in the fluid outlet line 520 causes the second valve 582S to close, thereby inhibiting the first fluid 538 from receding from the fluid outlet line 520 back into the pump chamber 584.
In certain embodiments, the first fluid 538 within the fluid outlet line 520 is systematically moved toward and into the fluid receiver 18 (illustrated in
The gas source 514 is then turned off to allow the level of the first fluid 538 in the gas inlet line 516 to equilibrate with the environmental fluid level 42E. The second valve 582S closes, inhibiting any change in the level of the first fluid 538 in the fluid outlet line 520. Once the first fluid 538 in the gas inlet line 516 has equilibrated with the environmental fluid level 42E, the process of opening the gas source 514 to move the gas 546 downward in the gas inlet line 516 is repeated. Each such cycle raises the level of the first fluid 538 in the fluid outlet line 520 until a desired amount of the first fluid 538 reaches the fluid receiver 18. The gas cycling in this embodiment can be utilized regardless of the time required for the first fluid 538 to equilibrate, but this embodiment is particularly suited toward a relatively slow equilibration processes.
In the second embodiment illustrated in
With these designs, because the gas 546 is cycled up and down within the gas inlet line 516 and or pump chamber 584, and no pressurization of the riser pipe 30 (illustrated in
In an alternative embodiment, the docking apparatus 50 need not be completely removed from the riser pipe 630 to determine the well fluid level 642W. Rather, the docking apparatus 50 need only be moved upward to the disengaged position to permit the first zone 626 and the second zone 628 to be in fluid communication with one another, at which time the well fluid level 642W can be determined with the portable fluid level sensor 694.
However, in this embodiment, when the docking apparatus 750 is in the engaged position (
In this embodiment, the fluid collector 752 can be a screened or filtered intake positioned within the first zone 726 when the docking apparatus 750 is in the engaged position as illustrated in
However, in this embodiment, the pump assembly 854 is positioned beneath the docking apparatus 850 so that when the docking apparatus 850 is in the engaged position, the pump assembly 854 is positioned within the first zone 826. In other words, the pump assembly 854 is sized and shaped to fit through the docking receiver 848 when the docking apparatus 850 is moved between the engaged and the disengaged positions.
In certain embodiments, the fluid collector 852 can be a fluid filter positioned at the entrance of the pump chamber 884, near one of the valves of the pump assembly 854. The fluid filter can inhibit any sediment or other unwanted material from entering the pump chamber 884.
Further, in certain embodiments that utilize the pump assembly 854 positioned within the first zone 826 when the docking apparatus 850 is in the engaged position, the fluid collector 852 may or may not be present. In such embodiments that do not utilize the fluid collector 852, the pump assembly 854 can include a one-way valve 882 that allows the first fluid 838 to enter the pump chamber 884 directly. In these embodiments, the pump assembly 854 can include one or more one-way valves 882, as previously described herein.
The fluid collector 952A can be any type of fluid collector described herein. In the embodiment illustrated in
Additionally, in this embodiment, the well 912B includes a second fluid inlet structure 998B that is positioned above the docking receiver 948B, adjacent to the second zone 928. The second fluid inlet structure 998B can have a height 900B that varies depending upon the design requirements of the fluid monitoring system 910B. In one embodiment, the second fluid inlet structure 998B is used in conjunction with monitoring the well fluid level 942W, and can therefore have a height 900B that is less than approximately five feet. Alternatively, the second fluid inlet structure 998B can have a height 900B that is greater than five feet.
The second fluid inlet structure 998B can be secured to the riser pipe 930B and/or the docking receiver 948B. In one embodiment, the second fluid inlet structure 998B is not positioned immediately adjacent to the docking receiver 948B, but is positioned at a level that is somewhat above the docking receiver 948B so that there is a spacing 999 between the docking receiver 948B and the second fluid inlet structure 998B. The spacing 999 can be present to account for the presence of the docking apparatus 950B when in the engaged position, so that fluid flow into the riser pipe 930B through the second fluid inlet structure 998B is not substantially impeded.
The pressure sensor 996B can periodically or continuously monitor the well fluid level 942W, which can change independent of any sampling that may occur from the fluid inlet structure 929B below the docking receiver 948B. The second fluid inlet structure 998B and the pressure sensor 996B can also be used at various times for various purposes, such as for pump tests and/or slug tests for measuring permeability of the environment 11 (illustrated in
The fluid collector 952B can be any type of fluid collector described herein. In the embodiment illustrated in
Additionally, in this embodiment, the zone isolation assembly 1022A includes a manifold 1002A that can be positioned at or near a top end of the riser pipe 1030A, which can be at or above the surface region 32 (illustrated in
The vent 1004A can be in an open position to allow air or other fluid into the riser pipe 1030A, or in a closed position to inhibit air or fluid from entering the riser pipe 1030A following closure of the vent 1004A. In the open position, draw-down of the second fluid 40 (illustrated in
When sampling of the first fluid 38 from the first zone 1026 is completed, the vent 1004A is moved to the open position, and the well fluid level 1042W can be allowed to equilibrate with the environmental fluid level 1042E.
It is recognized that the manifold 1002A described herein can be utilized with any other suitable embodiment to achieve the desired effect of the manifold 1002A provided herein.
Further, in this embodiment, the zone isolation assembly 1022B includes the manifold 1002B having a vent 1004B similar to that illustrated in
In one embodiment, the fluid property sensor 1206 is a Fiber Bragg Grating (FBG) sensor (illustrated by a dotted line). As used herein, the FBG sensor includes an optical fiber cable with intrinsic sensor elements written into the core of the fiber. As broadband light is directed down the fiber, the grating produces a narrow-band reflection whose wavelength is proportional to the modulation periodicity of the refractive index. The remainder of the light passes through the grating and may be used to interrogate other sensors written at different wavelengths.
With this design, multiple channels of data can be carried along a single fiber substantially simultaneously. The properties of the fluid that can be monitored with the FBG sensor include one or more of physical, chemical and/or electrical properties. More specifically, these properties can include pressure, chemistry, flow, refractive index, specific conductivity, temperature, oxidation reduction potential, pH, and dissolved oxygen, as non-exclusive examples. The FBG sensor can measure a specific fluid property at multiple levels within the well 1212, multiple fluid properties each at a particular level within the well 1212, or multiple fluid properties each at a multiple levels within the well 1212.
In this embodiment, the FBG sensor can be positioned within the first zone 1226 and/or the second zone 1228. Stated another way, the FBG sensor can monitor or measure fluid properties in an isolated environment (in the first zone 1226 when the docking apparatus 1250 is in the engaged position), or in a non-isolated environment (in the first zone 1226 and/or the second zone 1228 while the docking apparatus 1250 is in the disengaged position).
In this embodiment, the fluid collector 1552 is a passive diffusion sampler, such as a passive diffusion bag. In one embodiment, the passive diffusion sampler 1552 can be formed from materials such as a low-density polyethylene lay-flat tubing bags that are filled with distilled and/or deionized water (indicated as O's in
Before the docking apparatus 1550 is in the engaged position, the fluid (indicated by X's in
The passive diffusion sampler 1552 is allowed a predetermined time period (approximately 2 or 3 weeks in one non-exclusive example) within the isolated first zone 1526 to equilibrate with the first fluid 1538 in the first zone 1526. With this design, isolation of the passive diffusion sampler 1552 within the first zone 1526 reduces or eliminates diffusion-based averaging effects from the second zone 1528 on VOC concentrations. Additionally, passive diffusion bags are relatively inexpensive in comparison to pump assemblies and other pumping devices. Because a pump assembly is not necessary for use with passive diffusion samplers 1552, the cost of this type of system is reduced.
After the predetermined time period, the passive diffusion sampler 1552 is removed from the well 1512. The first fluid 1538 (indicated as dots in
In this embodiment, the fluid collectors 1752 are a plurality of passive diffusion samplers, such as a chain of the passive diffusion bags previously described. With this design, subtle or moderate changes in fluid chemistry with depth can be monitored in the first fluid 1738 (indicated as dots in
In this embodiment, the fluid collector 1852 is a pressurizable bailer. In one embodiment, the bailer 1852 includes a one-way valve 1807 that closes when the bailer 1852 is pressurized and opens when the bailer 1852 is unpressurized. Alternatively, the bailer 1852 can be non-pressurized. In the case of the pressurized bailer 1852, a gas source 14 (illustrated in
Once the docking apparatus 1850 is in the engaged position (
In one embodiment, the fluid monitoring system 1910 also includes a dispersion fluid retainer 1903 that retains the dispersion fluid 1901, a gas supply 1914 that supplies a gas 1946, and a fluid inlet line 1905 that is coupled to the docking apparatus 1950. The fluid inlet line 1905 can be formed from any suitable material that is compatible with the type of dispersion fluid 1901 to be used in the system 1910. For example, the fluid inlet line 1905 can be formed from various plastics, metal, fiberglass, ceramic, etc. The dispersion fluid retainer 1903 can selectively release the dispersion fluid 1901 into the fluid inlet line 1905 as needed. The gas supply 1914 can be opened to forcibly move the gas 1946 through the fluid inlet line 1905, which in turn forces the dispersion fluid 1901 downward and through the docking apparatus 1950 into the first zone 1926 via the fluid disperser 1953 while the docking apparatus 1950 is in the engaged position. In the engaged position, the zone isolation assembly 1922 isolates the dispersion fluid 1901 within the first zone 1926, while inhibiting the dispersion fluid 1901 from moving into the second zone 1928.
In this embodiment, the type of dispersion fluid 1901 used can vary depending upon the type of remediation that is necessary in the environment 1911. The dispersion fluid 1901 can include air, oxidizers, reducers, various bacteria, potassium permanganate, or any other suitable chemicals, either in liquid or gas form. The fluid monitoring system 1910 illustrated in
In an alternative embodiment (not shown), the perforated fluid disperser 1953 can be omitted, and the dispersion fluid 1901 can enter the first zone 1926 immediately after passing through the docking apparatus 1950 via the fluid inlet line 1905.
As indicated previously, the fluid monitoring systems provided herein can be installed by a variety of different methods.
The new length or section of drive casing 2081 is then lowered over the new section of riser pipe 2030 and threaded to secure attachment—with the drive casing 2081 rising slightly higher than the riser pipe 2030. A percussion cap (not shown) can be placed over the top of the drive casing 2081. A drive hammer 2083 or hydraulic ram can be used to vertically advance the drive casing 2081, with the riser pipe 2030 passively advancing along with the drive casing 2081.
When total depth is reached, the drive casing 2081 is retracted (retraction indicated by two steps 2087). With the drive cone 2085 attached to the bottom of the fluid inlet structure 2029, the drive cone 2085 remains at the bottom of the borehole while the drive casing 2081 is retracted. After the drive casing 2081 is fully removed from the borehole, the top section of riser pipe 2030 can remain for above-ground completions, or can be removed for flush mounted surface completions. The docking apparatus 2050, the fluid collector 2052 and/or a pump assembly 2054 can be inserted inside the direct push well 2012 for collecting the first fluid 38 (illustrated in
It is recognized that the various embodiments illustrated and described herein are representative of various combinations of features that can be included in the fluid monitoring system 10 and the zone isolation assemblies 22. However, numerous other embodiments have not been illustrated and described as it would be impractical to provide all such possible embodiments herein. It is to be understood that an embodiment of the zone isolation assembly 22 can include any of the docking receivers 48, docking apparatuses 50, fluid collectors 52, pump assemblies 54, and any of the other structures described herein depending upon the design requirements of the fluid monitoring system 10 and/or the subsurface well 12, and that no limitations are intended by not specifically illustrating and describing any particular embodiment.
Further, it is recognized that a well array of a plurality of subsurface wells 12 can be installed in a single borehole. For example, from 2-24 subsurface wells 12, also referred to as nested wells 12, can be installed in a borehole so that the zone isolation assembly 22 of each well 12 is positioned at two or more different depths within a given borehole. With this design, zones from different depths can be isolated to simultaneously monitor and/or analyze fluid properties from these different depths.
The arrangement of each well array can vary. For instance, the wells 12 can be arranged in a circle within the borehole. Alternatively, the wells 12 can utilize a different pattern or a random configuration within the borehole. Moreover, each well 12 in this type of system can utilize substantially similar or identical zone isolation assemblies 22, or each well can utilize any two or more different zone isolation assemblies 22 described herein.
While the particular fluid monitoring systems 10 and zone isolation assemblies 22 as herein shown and disclosed in detail are fully capable of obtaining the objects and providing the advantages herein before stated, it is to be understood that they are merely illustrative of various embodiments of the invention. No limitations are intended to the details of construction or design herein shown other than as described in the appended claims.
This Application claims the benefit on U.S. Provisional Application Ser. No. 60/758,030 filed on Jan. 11, 2006, and on U.S. Provisional Application Ser. No. 60/765,249 filed on Feb. 3, 2006. The contents of U.S. Provisional Application Ser. Nos. 60/758,030 and 60/765,249 are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 60758030 | Jan 2006 | US | |
| 60765249 | Feb 2006 | US |
