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Publication numberUS20090250224 A1
Publication typeApplication
Application numberUS 12/062,635
Publication dateOct 8, 2009
Filing dateApr 4, 2008
Priority dateApr 4, 2008
Publication number062635, 12062635, US 2009/0250224 A1, US 2009/250224 A1, US 20090250224 A1, US 20090250224A1, US 2009250224 A1, US 2009250224A1, US-A1-20090250224, US-A1-2009250224, US2009/0250224A1, US2009/250224A1, US20090250224 A1, US20090250224A1, US2009250224 A1, US2009250224A1
InventorsAdam D. Wright, Lewis Norman, Roger L. Schultz
Original AssigneeHalliburton Energy Services, Inc.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Phase Change Fluid Spring and Method for Use of Same
US 20090250224 A1
Abstract
A phase change fluid spring (450) for actuating a downhole tool (50) in a wellbore. The phase change fluid spring (450) includes a housing (114) defining a fluid chamber (120) and a phase change fluid disposed within the fluid chamber (120). The phase change fluid is in a first phase and at a first pressure at the surface. The phase change fluid is in a second phase and at a second pressure in the wellbore, the second pressure being greater than the first pressure. The phase change fluid is operable to store and release energy downhole to actuate the downhole tool (50).
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Claims(25)
1. A tool for use in a testing string disposed in a wellbore and forming an annulus therewith, the tool comprising:
a housing defining a central flow conducting passage;
a circulating valve disposed within the housing operable to control fluid communication between the central flow conducting passage and the exterior of the housing;
a passageway valve disposed within the central flow conducting passage operable to control fluid flow through the central flow conducting passage; and
a phase change fluid spring operably associated with the circulating valve and the passageway valve, the phase change fluid spring operates in response to changes in pressure in the annulus, wherein the phase change fluid spring contains a fluid that is in a first phase at a first pressure at the surface and a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.
2. The tool as recited in claim 1 wherein the phase change fluid spring stores and releases energy responsive to changes of annulus pressure.
3. The tool as recited in claim 1 wherein the first phase is a liquid phase.
4. The tool as recited in claim 1 wherein the second phase is one of a gas phase and a supercritical fluid phase.
5. The tool as recited in claim 1 wherein the first pressure is less than about 1,500 psi.
6. The tool as recited in claim 1 wherein the fluid is at least one of carbon dioxide, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon, acetone and mixtures of thereof.
7. A tool for use in a testing string disposed in a wellbore and forming an annulus therewith, the tool comprising:
a housing defining a central flow conducting passage;
an operating element disposed within the central flow conducting passage operable between two positions, a first position wherein the flow conducting passage through the tool is blocked, and a second position wherein the flow conducting passage is not blocked;
a fluid circulating assembly disposed within the housing operable between two positions, a first position wherein fluid communication is allowed between the annulus and the central flow conducting passage and a second position wherein fluid communication between the annulus and the central flow conducting passage is blocked;
an operating mandrel assembly slidably disposed within the housing and operably associated with the operating element and the fluid circulating assembly, the operating mandrel assembly operable to move between a plurality of positions such that the operating element and the fluid circulating assembly are actuated to configure the tool into distinct operative modes; and
a phase change fluid spring operably associated with the operating mandrel assembly, the phase change fluid spring operates in response to changes in pressure in the annulus, wherein the phase change fluid spring contains a fluid that is in a first phase at a first pressure at the surface and a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.
8. The tool as recited in claim 7 further comprising a pressure conducting channel within the exterior housing, the pressure conducting channel in fluid communication with the phase change fluid spring and the annulus for communicating changes in annulus pressure to the phase change fluid spring.
9. The tool recited in claim 7 wherein the phase change fluid spring stores and releases energy responsive to changes of annulus pressure.
10. The tool as recited in claim 7 wherein the first phase is a liquid phase.
11. The tool as recited in claim 7 wherein the second phase is one of a gas phase and a supercritical fluid phase.
12. The tool as recited in claim 7 wherein the first pressure is less than about 1,500 psi.
13. The tool as recited in claim 7 wherein the fluid is at least one of carbon dioxide, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon, acetone and mixtures of thereof.
14. A method for actuating a downhole tool disposed within a wellbore, the method comprising:
filling a fluid spring with a phase change fluid at the surface, the phase change fluid being in a liquid phase during the filling and being maintained at a first pressure in the fluid spring at the surface;
operably associating the fluid spring with the downhole tool;
lowering the downhole tool and the fluid spring into the wellbore to a desired depth such that the phase change fluid transitions from the liquid phase to one of a gas phase and a supercritical phase and to a second pressure that is higher than the first pressure;
pressurizing the phase change fluid in the fluid spring downhole such that energy to stored in the fluid spring; and
releasing the energy stored in the fluid spring to actuate the downhole tool.
15. The method as recited in claim 14 wherein the step of filling a fluid spring with a phase change fluid at the surface further comprises filling the fluid spring with at least one of carbon dioxide, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon, acetone and mixtures of thereof.
16. The method as recited in claim 14 wherein the step of filling a fluid spring with a phase change fluid at the surface further comprises filling the fluid spring such that the first pressure is less than about 1,500 psi.
17. The method as recited in claim 14 wherein the step of pressurizing the phase change fluid in the fluid spring downhole further comprises increasing the pressure in an annulus surrounding the downhole tool.
18. The method as recited in claim 14 wherein the step of releasing the energy stored in the fluid spring to actuate the downhole tool further comprises reducing the pressure in an annulus surrounding the downhole tool.
19. The method as recited in claim 14 further comprising repeating the steps of pressurizing the phase change fluid in the fluid spring downhole and releasing the energy stored in the fluid spring to actuate the downhole tool through a plurality of positions by sequentially increasing and decreasing the pressure in an annulus surrounding the downhole tool.
20. A fluid spring for actuating a downhole tool in a wellbore, the fluid spring comprising:
a housing defining a fluid chamber; and
a phase change fluid disposed within the fluid chamber, the phase change fluid in a first phase at a first pressure at the surface and in a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.
21. The fluid spring as recited in claim 20 wherein the first phase is a liquid phase.
22. The fluid spring as recited in claim 20 wherein the second phase is one of a gas phase and a supercritical fluid phase.
23. The fluid spring as recited in claim 20 wherein the first pressure is less than about 1,500 psi.
24. The fluid spring as recited in claim 20 wherein the second pressure is greater than about 10,000 psi.
25. The fluid spring as recited in claim 20 wherein the fluid is at least one of carbon dioxide, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon, acetone and mixtures of thereof.
Description
TECHNICAL FIELD OF THE INVENTION

This invention relates, in general, to a fluid spring operable to store and release energy downhole and, in particular, to a phase change fluid spring that contains a fluid that transitions from a liquid phase at a first pressure on the surface to a gas or supercritical phase at a second, higher pressure downhole.

BACKGROUND OF THE INVENTION

Without limiting the scope of the present invention, its background is described with reference to the operation of annulus pressure responsive downhole tools, as an example.

In oil and gas wells, it is common to conduct well testing and stimulation operations to determine production potential and enhance that potential. Annulus pressure responsive downhole tools have been developed which operate responsive to pressure changes in the annulus between the testing string and the wellbore casing that can sample formation fluids for testing or circulate fluids therethrough. These tools typically incorporate both a ball valve and lateral circulation ports. Both the ball valve and circulation ports are operable between open and closed positions. Commonly, these tools are capable of operating in different modes such as a drill pipe tester valve, a circulation valve and a formation tester valve, as well as providing its operator with the ability to displace fluids in the pipe string above the tool with nitrogen or another gas prior to testing or retesting. A popular method of employing the circulating valve is to dispose it within a wellbore and maintain it in a well test position during flow periods with the ball valve open and the circulation ports closed. At the conclusion of the flow periods, the tool is moved to a circulating position with the ports open and the ball valve closed. The tool may be operated by a ball and slot type ratchet mechanism which provides opening and closing of the valve responsive to a series of annulus pressure fluctuations.

To change the pressure in the annulus between the testing string and the wellbore casing, a surface pump in communication with the annulus pressurizes the fluid located in the annulus. The pressurized fluid in the annulus acts on a chamber located in the annulus pressure responsive downhole tool to increase the pressure of a pressurized gas in the chamber. This fluid spring is able to store the pressure for later use, for example, to operate the annulus pressure responsive downhole tool. This process may be repeated such that the annulus pressure responsive downhole tool may be operated through a plurality of cycles. Specifically, the annulus pressure responsive downhole tool is cycled by sequentially charging the fluid spring by increasing the annulus pressure then decreasing the annulus pressure which allows the stored pressure in the fluid spring to operate the annulus pressure responsive downhole tool as desired.

Many of these annulus pressure responsive downhole tools require several pressurization and depressurization cycles to fully operate their mechanisms, such as circulating valve ratchets and the like. For instance, some tools may require 15 or more cycles of pressurization and depressurization in the annulus to move the tool out of the well test position, into the circulating position and back again.

Typically, the hydrostatic pressure alone of the fluid in the annulus near the operating location of the tool may be 10,000 psi to 20,000 psi. To counter this pressure, the fluid spring must contain a gas pressure that is approximately equal to or exceeds that which is expected in the downhole environment. Accordingly, current fluid springs are pressurized with nitrogen at the surface to pressures that approximate the downhole pressure, for example, 20,000 psi. Use of such high pressures at the surface presents a very substantial safety risk to operating personnel during the charging and handling of these fluid springs. Moreover, if very high hydrostatic pressures are encountered downhole, it may be commercially unreasonable or impractical to charge the fluid springs to these pressures at the surface.

It would be desirable, therefore, to employ a fluid spring that does not require such high surface charges while still providing sufficient pressure downhole to act against hydrostatic pressure in the annulus. Additionally, it would be desirable to employ a fluid spring that is capable of storing and releasing energy in downhole environments having very high hydrostatic fluid pressures.

SUMMARY OF THE INVENTION

The present invention disclosed herein comprises phase change fluid spring operable for use with a downhole tool such as an annulus pressure responsive downhole testing tool. The phase change fluid spring containing a phase change fluid that is chargeable at the surface to significantly lower pressures while providing higher pressures downhole to actuate the downhole tool. The phase change fluid spring of the present invention achieves this result without the need of high-pressure charging systems on the surface. In addition, the phase change fluid spring provides energy storing capacity in very high pressure downhole conditions without requiring comparative high pressure surface charging.

Broadly stated, the present invention is directed to a fluid spring for actuating a downhole tool in a wellbore. The fluid spring includes a housing defining a fluid chamber and a phase change fluid disposed within the fluid chamber. The phase change fluid is in a first phase at a first pressure at the surface and a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.

In one embodiment of the fluid spring, the first phase is a liquid phase and the second phase is one of a gas phase and supercritical fluid phase. In another embodiment of the fluid spring, the first pressure is less than about 1,500 psi and the second pressure is greater than 10,000 psi. In yet another embodiment of the fluid spring, the fluid is at least one of carbon dioxide, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon, acetone and mixtures of thereof.

In another aspect, the present invention is directed to a method for actuating a downhole tool disposed within a wellbore. The method includes filling a fluid spring with a phase change fluid at the surface, the phase change fluid being in a liquid phase during the filling and being maintained at a first pressure in the fluid spring at the surface, operably associating the fluid spring with the downhole tool, lowering the downhole tool and the fluid spring into the wellbore to a desired depth such that the phase change fluid transitions from the liquid phase to one of a gas phase and a supercritical phase and to a second pressure that is higher than the first pressure, pressurizing the phase change fluid in the fluid spring downhole such that energy to stored in the fluid spring and releasing the energy stored in the fluid spring to actuate the downhole tool.

In the method, pressurizing the phase change fluid in the fluid spring downhole may be achieved by increasing the pressure in an annulus surrounding the downhole tool. Likewise, releasing the energy stored in the fluid spring to actuate the downhole tool may be achieved by reducing the pressure in an annulus surrounding the downhole tool. In some implementation, it may be desirable to repeat the steps of pressurizing the phase change fluid in the fluid spring downhole and releasing the energy stored in the fluid spring to actuate the downhole tool through a plurality of positions. This may be achieved by sequentially increasing and decreasing the pressure in the annulus surrounding the downhole tool.

In a further aspect, the present invention is directed to a tool for use in a testing string that is disposed in a wellbore. The tool includes a housing defining a central flow conducting passage. A circulating valve is disposed within the housing operable to control fluid communication between the central flow conducting passage and the exterior of the housing. A passageway valve is disposed within the central flow conducting passage operable to control fluid flow through the central flow conducting passage. A phase change fluid spring is operably associated with the circulating valve and the passageway valve. The phase change fluid spring operates in response to changes in pressure in the annulus, wherein the phase change fluid spring contains a fluid that is in a first phase at a first pressure at the surface and a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.

In another aspect, the present invention is directed to a tool for use in a testing string disposed in a wellbore. The tool includes a housing defining a central flow conducting passage. An operating element is disposed within the central flow conducting passage and is operable between two positions, a first position wherein the flow conducting passage through the tool is blocked and a second position wherein the flow conducting passage is not blocked. A fluid circulating assembly is disposed within the housing and is operable between two positions, a first position wherein fluid communication is allowed between the annulus and the central flow conducting passage and a second position wherein fluid communication between the annulus and the central flow conducting passage is blocked. An operating mandrel assembly is slidably disposed within the housing and is operably associated with the operating element and the fluid circulating assembly. The operating mandrel assembly is operable to move between a plurality of positions such that the operating element and the fluid circulating assembly are actuated to configure the tool into distinct operative modes. A phase change fluid spring is operably associated with the operating mandrel assembly. The phase change fluid spring operates in response to changes in pressure in the annulus, wherein the phase change fluid spring contains a fluid that is in a first phase at a first pressure at the surface and a second phase at a second pressure in the wellbore, the second pressure being greater than the first pressure.

In one embodiment, the tool includes a pressure conducting channel within the housing. The pressure conducting channel is in fluid communication with the phase change fluid spring and the annulus for communicating changes in annulus pressure to the phase change fluid spring.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts in which:

FIG. 1 is a schematic illustration of a phase change fluid spring coupled within a tool string operating from an offshore platform according to an embodiment of the present invention;

FIGS. 2A-2J are half section views of an exemplary testing tool with a phase change fluid spring of the present invention in a well test mode according to an embodiment of the present invention;

FIG. 3 is a front view of a ratchet slot mandrel section that has been depicted as a flat plate of the testing tool with a phase change fluid spring according to an embodiment of the present invention;

FIGS. 4A-4B are half section views of a phase change fluid spring connected to a phase change fluid source and hydraulic fluid source for charging the phase change fluid spring according to an embodiment of the present invention; and

FIG. 5 is a phase diagram for a phase change fluid used in the phase change fluid spring according to an embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts which can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention, and do not delimit the scope of the present invention.

Referring initially to FIG. 1, the present invention is shown schematically incorporated in a testing string deployed in an offshore oil or gas well. Platform 2 is shown positioned over a submerged oil or gas wellbore 4 located in the sea floor 6, wellbore 4 penetrating potential producing formation 8. Wellbore 4 is shown to be lined with steel casing 10, which may be cemented into place. A subsea conduit or riser 12 extends from the deck 14 of platform 2 to a subsea wellhead 16, which includes a blowout preventer 18. Platform 2 supports a derrick 20 thereon, as well as a hoisting apparatus 22, and a pump 24 which communicates with the wellbore 4 via control conduit 26, which extends to annulus 46 below blowout preventer 18.

A testing string 30 is shown disposed in wellbore 4, with blowout preventer 18 closed thereabout. Testing string 30 includes an upper drill pipe string 32 which extends downward from platform 2 to wellhead 16. Upper drill pipe string 32 is connected to a hydraulically operated test tree 34, below which extends intermediate pipe string 36. Slip joint 38 may be included in string 36 to compensate for vertical motion imparted to platform 2 by wave action. Below slip joint 38, intermediate string 36 extends downwardly to a testing tool with phase change fluid spring 50 of the present invention. Below testing tool with phase change fluid spring 50 is a lower pipe string 40, extending to a tubing seal assembly 42, which stabs into a packer 44. Above the tubing seal assembly 42 on the lower pipe string 40 is a tester valve 41, which may be of any suitable type known in the art. When set, packer 44 isolates upper wellbore annulus 46 from lower wellbore 48. Packer 44 may be any suitable packer well known in the art. Tubing seal assembly 42 permits testing string 30 to communicate with lower wellbore 48 through a perforated tail pipe 52. In this manner, formation fluids from formation 8 may enter lower wellbore 48 through the perforations 54 in casing 10, and flow into testing string 30.

After packer 44 is set in wellbore 4, a formation test for testing the production potential of formation 8 may be conducted by controlling the flow of fluid from formation 8 through testing string 30 using variations in pressure to operate testing tool with phase change fluid spring 50. The pressure variations are effected in upper annulus 46 by pump 24 and control conduit 26, utilizing associated relief valves (not shown). Prior to the actual test, however, the pressure integrity of testing string 30 may be tested with the valve ball of the testing tool with phase change fluid spring 50 closed in the tool's drill pipe tester mode. Testing tool with phase change fluid spring 50 may be run into wellbore 4 in its drill pipe tester mode, or it may be run in its circulation valve mode to automatically fill with fluid, and be cycled to its drill pipe mode thereafter. As the ball valve in testing tool with phase change fluid spring 50 of the present invention is opened and closed in its formation tester valve mode, formation pressure, temperature and recovery time may be measured during the flow test through the use of instruments incorporated in testing string 30 as known in the art, such as Bourdon tube-type mechanical gauges, electronic memory gauges and sensors run on wireline from platform 2 inside testing string 30 prior to the test. If the formation to be tested is suspected to be weak and easily damageable by the hydrostatic pressure of fluid in testing string 30, testing tool with phase change fluid spring 50 may be cycled to its displacement mode and nitrogen or other inert gas under pressure employed to displace fluids from the string prior to testing or retesting.

It may also be desirable to treat the formation 8 in conjunction with the testing program while testing string 30 is in place. Treatment programs may include hydraulically fracturing the formation or acidizing the formation. Such a treatment program is conducted by pumping various chemicals and other materials down the flow bore of testing string 30 at a pressure sufficient to force the chemicals and other materials into the formation. The chemicals, materials and pressures employed will vary depending on the formation characteristics and the desired changes thought to be effective in enhancing formation productivity. In this manner, it is possible to conduct a testing program to determine treatment effectiveness without removal of testing string 30. If desired, treating chemicals may be spotted into testing string 30 from the surface by placing the testing tool with phase change fluid spring 50 in its circulation valve mode, and displacing string fluids into the annulus prior to opening the ball valve in the testing tool with phase change fluid spring 50.

At the end of the testing and treating programs, the circulation valve mode of testing tool with phase change fluid spring 50 is employed, the circulation valve opened, and formation fluids, chemicals and other injected materials in testing string 30 circulated from the interior of testing string 30 are pumped back up the testing string 30 using a clean fluid. Packer 44 is then released (or tubing seal 42 withdrawn if packer 44 is to remain in place) and testing string 30 withdrawn from wellbore 4.

FIGS. 2A-2J illustrate a testing tool with phase change fluid spring 50. Testing tool with phase change fluid spring 50 is shown in section, enclosing a central flow conducting passage 56. As may be appreciated by reference to the drawings, connections of components are often complimented by the use of O-rings or other conventional seals. The use of such seals is well known in the art and, therefore, will not be discussed in detail. Commencing at the top of the testing tool with phase change fluid spring 50, upper adapter 100 has threads 102 therein at its upper end, whereby testing tool with phase change fluid spring 50 is secured to drill pipe in the testing string 30. Upper adapter 100 is secured to valve housing 104 at threaded connection 106. Valve housing 104 contains a valve assembly (not shown), such as is well known in the art, and a lateral bore 108 in the wall thereof, communicating with downwardly extending longitudinal phase change fluid charging channel 110.

Valve housing 104 is secured by threaded connection 112 at its outer lower end to tubular pressure case 114, and by threaded connection 116 at its inner lower end to gas chamber mandrel 118. Case 114 and mandrel 118 define a pressurized gas chamber 120 and an upper oil chamber 122, the two being separated by a floating annular piston 124. Channel 110 is in communication with chamber 120.

The upper end of oil channel coupling 126 extends between case 114 and gas chamber mandrel 118, and is secured to the lower end of case 114 at threaded connection 128. A plurality of longitudinal oil channels 130 spaced around the circumference of coupling 126 (one shown), extend from the upper terminal end of coupling 126 to the lower terminal end thereof. Radially drilled oil fill ports 132 extend from the exterior of testing tool with phase change fluid spring 50, intersecting with channels 130 and closed with plugs 134. The lower end of coupling 126, includes a downwardly facing lower side 127 and is secured at threaded connection 140 to the upper end of connector housing 123.

Connector housing 123 is connected at its lower portion by threaded connection 125 to the fluid metering assembly 142 which is constructed primarily of upper and lower fluid flow housings 144 and 146 and a metering nut 148. While an exemplary construction for the fluid metering assembly 142 is described herein, it is understood that other constructions which perform these functions may also be used.

The upper fluid flow housing 144 is connected at its lower portion by threaded connection 154 to the lower fluid flow housing 146 which is, in turn, connected at thread 156 to ratchet case 158, with oil fill ports 160 extending through the wall of case 158 and closed by plugs 162. Ratchet case 158 presents an inwardly projecting, upwardly facing annular shoulder 164 (see FIG. 2D) on its inner surface which forms and separates an upper expanded bore 166 from a lower reduced diameter bore 168 below. The expanded bore 166 defines a ratchet chamber 170.

Referring now to FIG. 2C, the lower portion of the metering nut 148 is engaged at threads 190 to the upper fluid flow housing 144. The metering nut 148 includes an upward facing port 192 communicating with a bore 194 extending downwardly in nut 148. A fluid restrictor 196 is disposed within the bore 194. A radially inward facing lateral hole 198 in the metering nut 148 permits fluid communication radially inward between the annular gap 182 and the inner radial separation or clearance 199 between the metering nut 148 and the bypass mandrel 206. When connected, metering nut 148 and upper fluid flow housing 144, form an external annular groove 200 having a V-shaped cross-section. Between the upper portion of the metering nut 148 and the upper fluid flow housing 148 lies fluid passage 195 which extends between the groove 200 above and upper annular gap 182 below. An elastomeric O-ring 202 is seated within the groove 200 so as to block fluid entry into the groove 200 and between the two pieces, but the O-ring 202 may be urged radially outward by fluid pressure to permit fluid communication from the passage 195 outward through the groove 200. A radial separation or clearance 204 is present between the metering nut 148 and connector housing 123.

The lower fluid flow housing 146 includes a pair of longitudinal passages 172 which communicates fluid between ratchet chamber 170 below and a lower annular gap 176 above defined at the connection of upper fluid flow housing 144 and lower fluid flow housing 146.

As depicted in FIG. 2D, on one radial side proximate its bottom portion, upper fluid flow housing 144 encases an inwardly opening non-annular cavity 178 and an adjoining annular chamber 179. The upper fluid flow housing 144 also encases a first passage 180 which runs between an upper annular gap 182 formed between metering nut 148 and upper fluid flow housing 144 and the non-annular cavity 178 below. A plug 184 is disposed within the first passage 180 just below the upper annular gap 182 so as to block fluid flow therethrough. A radially outward facing port 186 within the upper fluid flow housing 144 permits fluid communication between the first passage 180 and the radial clearance 204. A second passage 188 also communicates fluid between the lower annular gap 176 and upper annular gap 182 above.

A bypass mandrel 206 (FIGS. 2B-2C) is disposed within oil channel coupling 126, connector housing 123, and fluid metering assembly 142. A fluid chamber 129 is formed between mandrel 206 and housing 123 with coupling 126 at its upper end and metering assembly 142 at its lower end. One or more upper bypass grooves 208 are cut into the outer surface of bypass mandrel 206 such that, when the bypass mandrel is in its lower position fluid may be communicated along grooves 208 between fluid chamber 129 and lateral hole 198.

The fluid metering assembly 142 presents an upper end 150 and lower end 152. The fluid metering assembly 142 includes an upward flow path and a downward flow path for communication therebetween. In operation, the fluid metering assembly 142 permits relatively unrestricted upward movement of fluid through upward flow path 188, but will meter fluid downward over a period of time through the downward flow path.

When an upward pressure differential exists at the lower end 152 of assembly 142, the fluid metering assembly 142 provides an upward flow path which communicates fluid from the ratchet chamber 170 to fluid chamber 129 without presenting significant resistance. Traveling along the upward flow path, fluid enters passages 172 at lower end 152 and is communicated into the lower annular gap 176, then upward within the second passage 188 of upper fluid flow housing 144 to upper annular gap 182. Fluid then enters passage 195 and flows radially outward through the V-shaped groove 200, through the clearance 204 and into fluid chamber 129. Fluid will displace the O-ring 202 much more easily than it can pass through fluid restrictor 196, and flow past the O-ring 202 presents no significant restriction.

When a downward pressure differential exists at upper end 150, the fluid metering assembly 142 provides a downward flow path to communicate fluid downward from fluid chamber 129 to ratchet chamber 170. The downward flow path, unlike the upward path, provides flow resistance. By way of explaining the downward flow path, fluid movement within the metering assembly 142 is described as follows. Fluid first enters the radial clearance 204 surrounding the metering nut 148. Being blocked from entry into the groove 200 by the O-ring 202, the fluid passes further downward through the clearance 204 and enters the port 186 to move into and downward through the first passage 180 to the non-annular cavity 178 and non-annular chamber 179. As the fluid cannot progress beyond the non-annular gap 178 and chamber 179, it must instead take an alternate path in which it passes downwardly through the upwardly facing port 192, bore 194 and fluid restrictor 196 to enter the upper annular gap 182 where it is transmitted to the second passage 188 of upper fluid flow housing 144 and downward to the lower annular gap 176 and can then move into ratchet chamber 170 through passages 172.

An annular piston 210 (FIG. 2C) is disposed within the fluid chamber 129 and affixed by lock rings 212 to bypass mandrel 206 to be axially moveable therewith. Piston 210 includes a longitudinal bore 211 therethrough having upper and lower enlarged diameter portions. An upper check valve 214 with an upwardly extending dart 216 within its upper end is disposed within the upper enlarged portion of bore 211. The upper check valve 214 is spring biased into a normally closed position which blocks upward fluid flow across it through the piston 210 but will permit downward fluid flow under pressure. Downward force upon the dart 216 will open the upper check valve to permit upward fluid flow therethrough. Lower check valve 218 is oppositely disposed from the upper check valve 214 within the lower enlarged portion of bore 211 of piston 210 and carries a downwardly extending dart 220 within its lower end. It is spring biased into a normally closed position against downward fluid flow, but will permit upward fluid flow under pressure. Upward force upon the dart 220 will open the lower check valve 218 to downward fluid flow therethrough.

The bypass mandrel 206 is axially slidable with respect to the oil channel coupling 126, housing 123, fluid chamber 129 and the fluid metering assembly 142 between an upper position proximate the lower end of gas chamber mandrel 118 and a lower position proximate the upper end of ratchet slot mandrel 222. Ratchet slot mandrel 222 extends upward from within ratchet case 158. The upper exterior 224 of ratchet slot mandrel 222 has a reduced, substantially uniform diameter, while the lower exterior 226 has a greater diameter so as to provide sufficient wall thickness for ratchet slots 228. Ratchet slot mandrel 222 includes an annular member 231 projecting radially outward and forming a piston seat 230 which faces upwardly and outwardly at the base of the upper exterior 224 of mandrel 222. There are preferably two such ratchet slots 228 extending longitudinally along the lower exterior of the ratchet slot mandrel 222.

The ratchet slot mandrel 222 is axially slidable within testing tool with phase change fluid spring 50 between upper and lower positions as will be described in greater detail shortly. Lower longitudinal bypass grooves 232 are cut into the upper exterior 224 of ratchet slot mandrel 222. The grooves 232 should be of sufficient width to permit fluid flow therealong. The lower bypass grooves 232 generally adjoin the lower fluid flow housing 144 and should be in such a location and of such a length that when the ratchet slot mandrel 222 is in its upper positions, the grooves 232 are located alongside the lower fluid flow housing 146 and no fluid flow occurs along the grooves. As the ratchet slot mandrel 222 is moved toward its lower positions, the grooves 232 will be moved downward such that fluid communication may occur between the annular chamber 179 and the ratchet chamber 170.

A ball sleeve assembly 234 surrounds ratchet slot mandrel 222 and comprises shuttle piston 236, upper sleeve 238, lower sleeve 240, and clamp 242 which connects sleeves 238 and 240.

Shuttle piston 236 is constructed similarly in structure and function to annular piston 210 and is fixedly attached to or unitarily fashioned with upper sleeve 238. The shuttle piston 236 surrounds the upper exterior 224 of the ratchet slot mandrel 222 within the ratchet chamber 170. Shuttle piston 236 includes a longitudinal bore 237 therethrough having upper and lower enlarged diameter portions. An upper check valve 244 with upwardly extending dart 246 within its upper end is disposed in the upper enlarged portion, and lower check valve 248 with downwardly extending dart 250 within its lower end is disposed within the lower enlarged portion. The lower check valve 248 and dart 250 are shown as angled outwardly within the shuttle piston 236 such that the dart 250 contacts shoulder 164 when ball sleeve assembly 234 is moved downward within the ratchet case 158.

The lower end 252 of the ratchet slot mandrel 222 is secured at threaded connection 254 to extension mandrel 256. A radial clearance 258 is present between the radial exterior of lower end 252 and the interior surface of ratchet case 158. The lower end 260 of ratchet case 158 is secured at threaded connection 262 to extension case 264 which surrounds the extension mandrel 256. Annular intermediate oil chamber 266 is defined by ratchet case 158 and extension mandrel 256. The intermediate oil chamber 266 is connected by oil channels 268 to lower oil chamber 270. Annular floating piston 272 slidingly seals the bottom of lower oil chamber 270 and divides it from the lower wall fluid chamber 274 into which pressure ports 282 in the wall of case 264 open.

The general construction and operation of ratchet-type assemblies is well known in the art. As will be appreciated by the discussion that follows, the testing tool with phase change fluid spring 50 of the present invention incorporates a ratchet assembly having a dual-path ratchet slot within which a ratchet member is directed. The primary path is cyclical and maintains the tool's components in the well test mode. The secondary path is contiguous to the first path, and redirection of the ratchet member into the second path permits the tool's components to be altered so that the tool may be reconfigured into alternative modes of operation.

Referring now to FIGS. 2E and 3, two ratchet balls 276 are found in ball seats 278 located on diametrically opposite sides of lower sleeve 240 and each project into a ratchet slot 228 of semi-circular cross-section. The configuration of ratchet slot 228 is shown in FIG. 3. As shown there, the ratchet slot 228 includes an installation groove 281 which has a depth greater than that of the ratchet slot 228 to permit the introduction and capture of balls 276 during assembly of the testing tool with testing tool with phase change fluid spring 50. The ratchet slot 228 includes a unique pattern or configuration having a number of ball positions, a, b, c, d1, d2, e1, e2, f1, f2, f3, f4, f5, f6 and f7. The ball positions correspond to the general positions for balls 276 along ratchet slot 228 during the various operations involving annulus pressurization changes. As the balls 276 follow the path of slot 228, lower sleeve 240 rotates with respect to upper sleeve 238, and axial movement of the ball sleeve assembly 234 is transmitted to ratchet slot mandrel 222 by balls 276.

Referring again to FIG. 2G, the lower end of extension case 264 includes oil fill ports 284 containing closing plugs 286. A nipple 288 is threaded at 290 at its upper end to extension case 264 and at 292 at its lower end to circulation displacement housing 294. The circulation displacement housing 294 possesses a plurality of circumferentially spaced, radially extending circulation ports 296, as well as one or more pressure equalization ports 298, extending through the wall thereof. A circulation valve sleeve 300 is threaded to the lower end of extension mandrel 256 at threaded connection 302. Valve apertures 304 extend through the wall of circulation valve sleeve 300 and are isolated from circulation ports 296 by annular seal 306, which is disposed in seal recess 308 formed by the junction of circulation valve sleeve 300 and a lower operating mandrel 310, the two being threaded together at 312. Operating mandrel 310 includes a reduced diameter, downwardly extending skirt having an exterior annular recess 314.

A collet sleeve 318, having collet fingers 320 at its upper end extending upwardly therefrom, engages the downwardly extending skirt 316 of operating mandrel 310 through the accommodation of radially, inwardly extending protuberances 322 received by annular recess 314. As is readily noted in FIGS. 2H-2I, protuberances 322 and the upper portions of collet fingers 320 are confined between the exterior of mandrel 310 and the interior of circulation displacement housing 294 thereby maintaining the connection.

Collet sleeve 318 includes coupling 324 at its lower end comprising radially extending flanges 326 and 328, forming an exterior annular recess 330 therebetween. A lower coupling 332 comprises inwardly extending flanges 334 and 336 forming an interior recess 338 therebetween and two ball operating arms 338. Couplings 324 and 332 are maintained in engagement by their location in annular recess 340 between ball case 342, which is threaded at 344 to circulation-displacement housing 294, and ball housing 346. Ball housing 346 is of substantially tubular configuration, having an upper smaller diameter portion 348 and a lower, larger diameter portion 350. Larger diameter portion 350 has two windows 352 cut through the wall thereof to accommodate the inward protrusion of lugs 354 on each of the two ball operating arms 338. Windows 352 extend from shoulder 356 downward to shoulder 358 adjacent threaded connection 360 with ball support 362. On the exterior of the ball housing 346, two longitudinal channels (location shown by phantom arrow 364) of arcuate cross-section and circumferentially aligned with windows 352, extend from shoulder 366 downward to shoulder 356. Ball operating arms 338, which are of substantially the same arcuate cross section as channels 364 and lower portion 350 of ball housing 346, lie in channels 364 and across windows 352, and are maintained in place by the interior wail 368 of ball case 342 and the exterior of portion 350 of ball housing 346.

The interior of ball housing 346 possesses upper annular seat recess 370, within which annular ball seat 372 is disposed, being biased downwardly against ball 374 by ring spring 376. Surface 378 of upper seat 372 comprises a metal sealing surface, which provides a sliding seal with the exterior 380 of valve ball 374.

Valve ball 374 includes a diametrical bore 382 therethrough of substantially the same diameter as bore 384 of ball housing 346. Two lug recesses 386 extend from the exterior 380 of valve ball 374 to bore 382.

The upper end 388 of ball support 362 extends into ball housing 346, and carries lower ball recess 390 in which annular lower ball seat 392 is disposed. Lower ball seat 392 possesses arcuate metal sealing surface 394 which slidingly seals against the exterior 380 of valve ball 374. When ball housing 346 is made lap with ball support 362, upper and lower ball seats 372 and 392 are biased into sealing engagement with valve ball 374 by spring 376.

Exterior annular shoulder 396 on ball support 362 is contacted by the upper ends 398 of splines 400 on the exterior of ball case 342, whereby the assembly of ball housing 346, ball operating arms 338, valve ball 374, ball seats 372 and 392 and spring 376 are maintained in position inside of ball case 342. Splines 400 engage splines 402 on the exterior of ball support 362, and, thus, rotation of the ball support 362 and ball housing 346 within ball case 342 is prevented.

Lower adaptor 404 protrudes at its upper end 406 between ball case 342 and ball support 362, sealing therebetween, when made up with ball support 362 at threaded connection 408. The lower end of lower adaptor 404 carries on its exterior threads 410 for making up with portions of a testing tool with phase change fluid spring 50.

When valve ball 374 is in its open position, as shown in FIG. 2I, a full open conducting passage 56 extends throughout testing tool with phase change fluid spring 50, providing an unimpeded path for formation fluids and/or for perforating guns, wireline instrumentation, etc.

It is noted that an exterior housing 414 for the testing tool with phase change fluid spring 50 may be made up of upper adapter 100, valve housing 104, pressure case 114, oil channel coupling 126, connector housing 123, upper and lower fluid flow housings 144 and 146, ratchet case 158, extension case 264, nipple 288, circulation displacement housing 294, ball case 342 and lower adaptor 404. The ratchet slot mandrel 222, extension mandrel 256, circulation valve sleeve 300, operating mandrel 310 may be thought of as an operating mandrel assembly indicated generally at 412.

An annulus pressure conducting channel capable of receiving, storing and releasing annulus pressure increases is formed by pressure ports 282, fluid chamber 274, floating piston 272, lower oil chamber 270, oil channels 268, intermediate oil chamber 266, ball sleeve assembly 234, ratchet chamber 170, fluid metering assembly 142, fluid chamber 129, longitudinal oil channels 130, upper oil chamber 122, floating piston 124 and pressurized gas chamber 120. The pressurized gas chamber 120 functions as a fluid spring while the other components of the pressure conducting channel serve as a pressure conducting passage to communicate fluid pressure changes between the annulus 46 and the fluid spring.

The circulation valve sleeve 300, valve apertures 304, annular seal 306, circulation displacement housing 294, and circulation ports 296 may be thought of as a fluid circulating assembly 416 which may be selectively opened and closed to permit fluid flow between the annulus 46 and the central flow conducting passage 56 of the testing tool with phase change fluid spring 50.

Referring to FIG. 1-3, operation of the testing tool with phase change fluid spring 50 of the present invention is described hereafter. As testing tool with phase change fluid spring 50 is run into the well in testing string 30, it is normally in its well test mode as shown in FIG. 2, with ball 374 in its open position and ball bore 382 aligned with tool bore 384. Circulation ports 296 are misaligned with circulation valve apertures 304, seal 306 preventing communication therebetween. With respect to FIG. 3, balls 276 will be proximately in position a in slot 228 as testing tool with phase change fluid spring 50 is run into the wellbore.

Pressure is increased in annulus 46 by pump 24 via control conduit 26. This increase in pressure is transmitted through pressure ports 282 (FIG. 2G) into well fluid chamber 274, where it acts upon the lower side of floating piston 272. Floating piston 272, in turn, acts upon a fluid, such as silicon oil, in lower chamber 270, which communicates via oil channels 268 with intermediate oil chamber 266. Fluid pressure in the intermediate oil chamber 266 flows around the lower end 252 of the ratchet slot mandrel 222 to exert upward fluid pressure upon the shuttle piston 236 which pulls ball sleeve assembly 234. Balls 276 move along slot 228 to position b via the association of the ratchet slot mandrel 222 and ball sleeve assembly 234, the ratchet slot mandrel 222 and the entire operating mandrel assembly 412 may be moved upward slightly but not a sufficient amount to affect either the valve ball 374 or the circulating assembly 416.

Fluid within ratchet chamber 170 is evacuated upward through the fluid metering assembly 142. By virtue of the upward flow path described above, the fluid is communicated into fluid chamber 129 without significant flow restriction. Annular piston 210 and the affixed bypass mandrel 206 are moved axially upward. Fluid above the piston 210 is evacuated upward from the fluid chamber 129 through longitudinal channels 130 into upper oil chamber 122 to urge floating piston 124 upward, thereby pressurizing the gas in chamber 120 to store the pressure increase.

As annulus pressure is subsequently bled off during depressurization, the pressurized gas in chamber 120 pushes downward against floating piston 124, this pressure is transmitted through fluid within upper oil chamber 122, channels 130 and fluid chamber 129. Annular piston 210 and the affixed bypass mandrel 206 are moved axially downward. Fluid from chamber 129 is transmitted downward into the ratchet chamber 170 through the downward flow path of the fluid metering assembly 142. Ball sleeve assembly 234 is, therefore, biased downwardly with ratchet balls 276 following the paths of slot 228 past position c, where they shoulder at position a. Downward travel of the ball sleeve assembly 234 is limited by engagement of the shuttle piston 236 on piston seat 230 (FIG. 2D). Again, any downward movement of the ratchet slot mandrel 222 and the operating mandrel assembly 412 will be slight and not sufficient to close the valve ball 374 or close the circulating assembly 416. As a result, the ratchet assembly may be thought of as providing a default position sequence with the well test position cycle 283 wherein the operating mandrel assembly 412 is maintained during annulus pressure changes in primary mandrel positions such that the valve ball 374 and the circulating assembly 416 are not affected.

As testing tool with phase change fluid spring 50 travels down to the level of the production formation 8 to be tested, at which position packer 44 is set, floating piston 272 moves upward under hydrostatic pressure, pushing ball sleeve assembly 234 upward and causing balls 276 to move toward position b. This movement does not change tool modes or open any valves. Upon testing tool with phase change fluid spring 50 reaching formation 8, packer 44 is set. The aforesaid feature is advantageous in that it permits pressuring of the wellbore annulus 46 to test the seal of packer 44 across the wellbore 4 without closing valve ball 374. It also permits independent operation of other annulus pressure responsive tools within testing string 30.

Increases in annulus pressure will move floating piston 272 and ball sleeve assembly 234 further upward, its movement ultimately being restricted by the shouldering out of balls 276 at ball position b within slot 228. Reduction in annulus pressure will move floating piston 272 and ball sleeve assembly 234 downward and cause balls 276 to move downward proximate ball position c and ultimately back to ball position a. The well annulus pressure may be increased and decreased as many times as desired without moving the testing toot with phase change fluid spring 50 out of the well test position, the balls 276 following the described well test position path 283, which is made up of the ball positions a, b, and c and the paths of slot 228 connecting them. Effectively, the well test position path 283 affords default position control for the testing tool with phase change fluid spring 50 by maintaining it in its well test position during regular annulus pressurization cycles.

The testing tool with phase change fluid spring 50 may be changed out of the well test position by increasing annulus pressure during the portion of the annulus pressure reduction sequence when balls 276 are proximate ball position c. As a result, annulus repressurization during a release of stored fluid pressure from the pressurized gas chamber 120 acts to override the default position control being provided for the operating mandrel assembly 222 by the well test position path 283. Fluid restriction provided by passage of fluid through the downward flow path in the fluid metering assembly 142 will provide a sufficiently metered downstroke so that an operator will have time to repressurize the annulus. It is expected that the time required for the ball sleeve assembly 234 to move fully downward so that the balls 276 essentially return to ball position a is approximately 10 minutes; the time required for the balls 276 to move only to position c is approximately 4 minutes. It should be apparent to one skilled in the art that the ratchet slot 228 and well test position path 283 might be altered such that the balls 276 are directed out of the well test position path 283 by an annulus pressure reduction which occurs during an increase of stored fluid pressure in the pressurized gas chamber 120.

A bypass mechanism is included in testing tool with phase change fluid spring 50 which shortens the length of time needed for selected portions of the metered downstroke to be completed. The bypass mechanism employs the upper and lower bypass grooves 208 and 232 to selectively permit fluid to bypass portions of the fluid metering assembly at specific points during the downstroke to shorten the downstroke. As the annular piston 210 and affixed bypass mandrel 206 are moved downward sufficiently, portions of the lengths of upper bypass grooves 208 are disposed below the upper end 150 and adjacent the clearance 199 and lateral hole 198 of fluid metering assembly 142. In other modes and/or cycles of the testing tool with phase change fluid spring 50, fluid communication occurs between the fluid chamber 129 and the upper annular gap 182. The bypass assembly thereby permits fluid from the fluid chamber 129 to bypass the fluid restrictor 196 and move into the second passage 188 of the upper fluid flow housing 144 where it may be readily transmitted downward into the ratchet chamber 170. The downward flow of fluid is thereby increased speeding up the downward stroke. By choice of width and length of the upper bypass grooves 208 as well as the placement upon the bypass mandrel 206, the amount and timing of fluid bypassing may be controlled.

The lower bypass grooves 232, which are located on the upper exterior 224 of the ratchet slot mandrel 222, are placed such that, when the mandrel 222 is in an upper position, such as in the well test position, the grooves 232 are generally adjacent the annular chamber 179 and no fluid flow occurs therealong. See FIG. 2D. As the mandrel 222 moves downward with respect to the housing 414, the lower portion of grooves 232 are moved adjacent the ratchet chamber 170 and fluid communication is permitted between the annular chamber 179 and ratchet chamber 170.

When the wellbore annulus is repressured to move the testing tool with phase change fluid spring 50 out of its well test position, the ball sleeve assembly 234 moves upward and balls 276 are moved along slot 228 from proximate ball position c to a point above ball position d1. The balls 276 have now been directed out of the well test position cycle shown at 283 on FIG. 3 and into a contiguous second ratchet path made up of the remainder of slot 281 to permit the operating mandrel assembly 412 to move to alternate mandrel positions wherein the positions of the valve ball 374 and circulating assembly 416 may be changed. Upward travel of the ball sleeve assembly 234 is ultimately limited as shuttle piston 236 encounters the lower end 152 of the fluid metering assembly 142. Downward force is exerted upon the dart 246 permitting upward fluid flow past the check valve 244 and a subsequent reduction in the upward pressure differential upon the ball sleeve assembly 234. As the pressure differential is reduced, balls 276 are shouldered at ball position d1.

Once the balls 276 have been located at ball position d1, further reduction of the annulus pressure shifts the testing tool with phase change fluid spring 50 into its blank position with the valve ball 374 being moved to a closed position. The operating mandrel assembly 412 is positioned lower with respect to the ball sleeve assembly and housing 414 due to engagement of the balls 276 with the ratchet slot mandrel 222 at ball position d1. The downward pressure differential upon ball sleeve assembly 234 urges it downward along with the operating mandrel assembly 412, collet sleeve 318 and ball operating arms 338 to close valve ball 374 such that its bore 382 is not aligned with the ball housing bore 384. As with other modes and/or cycles, this downward movement is not sufficient to align the circulation ports 296 with the valve apertures 304 and permit fluid communication therethrough. As a result, the circulating assembly 416 remains closed.

During a subsequent well annulus pressure increase and decrease cycle, balls 276 are moved along slot 228 to ball position e1. This will have the effect of moving the operating mandrel assembly 412 further downward with respect to the exterior housing 414. However, the fluid circulating assembly 416 remains closed. To prevent damage to the valve ball 374 and its surrounding parts as a result of excessive downward movement of the operating mandrel assembly 412, protuberances 322 may become disengaged from recess 314.

As well annulus pressure is increased and decreased once more, the balls 276 are moved from ball position e1 to position f1 causing the testing tool with phase change fluid spring 50 to be moved into its circulating position. In accordance with other modes and/or cycles, the valve ball 374 remains closed and the fluid circulating assembly 416 is opened by the alignment of the circulation ports 296 and valve apertures 304 to permit fluid communication between the central flow conducting passage 56 and the wellbore annulus 46. The testing tool with phase change fluid spring 50 will remain in the circulating position during subsequent annulus pressure change cycles where the balls 276 are moved sequentially to positions f2, f3, f4, f5, f6 and f7.

By way of further explanation of the mode changing and operating sequence of testing tool with phase change fluid spring 50, the reader should note that the tool only changes mode when balls 276 shoulder at specific positions on slot 228 during cycling of the tool since ratchet operation dictates the position of the operating mandrel assembly 412 within the housing 414. For example, testing tool with phase change fluid spring 50 changes mode at positions d1, f1, f7, and d2.

It is also noted that movement between some ball positions is effected by annulus pressure decrease followed by an increase rather than the increase/decrease cycle described above. With respect to FIG. 3, specifically, movement from f6 to f7, from f7 to e2 and from e2 to d2 is accomplished this way.

In addition to the embodiment described above, the phase change fluid spring of the present invention may be used with other downhole testing apparatuses that use a fluid spring to store energy and release stored energy to operate the testing apparatuses.

The phase change fluid contained in the pressurized gas chamber 120 is a fluid that is compressible to a liquid phase preferably at the surface, but that changes to a gas phase or supercritical phase at significantly higher pressures when located downhole in the wellbore 4 due to the temperatures in the wellbore 4. As described above, when phase change fluid spring is disposed downhole in the wellbore 4 it is operable to store energy then release the stored energy to operate the testing tool in the wellbore 4. As discussed below, a predetermined volume of phase change fluid is pressurized in the pressurized gas chamber 120 prior to being located downhole in the wellbore 4.

Referring next to FIGS. 4A-4B, an embodiment of a phase change fluid spring 450 is shown connected to an apparatus for charging the phase change fluid spring 450 with such a phase change fluid. The term phase change fluid as used herein means one or more fluids, elements, substances or mixtures of such fluids, elements or substances that has the physical properties of being in a liquid phase at surface temperatures and a first pressure such as 1,500 psi or less and that changes to a gas phase or supercritical phase at downhole temperatures having a corresponding higher pressure, preferably greater than 5,000 psi. More preferably the phase change fluid has a pressure in the pressurized gas chamber 120 of from about 8,000 psi to about 25,000 psi, and most preferably from about 10,000 psi to about 20,000 psi, when located downhole in the wellbore 4.

In the illustrated embodiment, phase change fluid spring 450 is charged with the phase change fluid on the surface prior to attaching phase change fluid spring 450 to the testing tool. Phase change fluid spring 450 is charged via lateral bore 108 that preferably includes a fitting or connector to connect to a fluid line 456 for receiving a supply of phase change fluid from a phase change fluid source 454. The pressure of the fluid entering phase change fluid spring 450 is monitored and controlled by a regulator 452 located between the phase change fluid source 454 and phase change fluid spring 450.

Preferably, pressurized gas chamber 120 is charged or pressurized with phase change fluid using floating piston 124 to maintain a constant pressure and to assure that the phase change fluid does not change phases during the charging process. This is achieve by pressurizing a second fluid 458 on the lower side of floating piston 124 when floating piston 124 is located at the top of gas chamber 120. The second fluid 458 may be an oil or other fluid from fluid reservoir 462 that initially fills upper oil chamber 122, longitudinal oil channels 130 and fluid supply line 460. Fluid supply line 460 is coupled to phase change fluid spring 450 via oil fill port 132. In this manner, the second fluid 458 is used to maintain a desired pressure within the pressurized gas chamber 120 while it is being charged or pressurized with the phase change fluid. Specifically, as phase change fluid enters pressurized gas chamber 120, floating piston 124 moves down acting against the pressure of the second fluid 458. As the pressurized gas chamber 120 is filled, the second fluid 458 may be bled off and captured back in the second fluid reservoir 462.

In one embodiment, the phase change fluid is in a liquid phase as it enters pressurized gas chamber 120 at the surface. The desired volume of phase change fluid placed in the pressurized gas chamber 120 may be determined using some commonly known gas equations. For example, one such equation is the Ideal Gas Equation:


PV=nRt   (I)

where P equals the pressure in atmospheres; V equals the volume of the pressurized gas chamber 120; n equals the number of moles of the phase change fluid in the pressurized gas chamber 120; T is the temperature in K of the phase change fluid; and R is a gas constant. In one aspect, the gas constant R=0.0821 liter·atmosphere·mole−1·K−1.

Another well known gas equation that may be applied to the determine the volume of phase change fluid to pressurize in the pressurized gas chamber 120 is the van der Waals Equation of State:


[P+a(n/v)2](V−nb)=nRT   (II)

where P is the pressure in a common unit, such as atmospheres; a is a van der Waals constant in a common unit, such as J·M3/mole2; n is the number of moles of phase change fluid; V is the volume in a common unit, such as m3; b is another van der Waals constant in a common unit, such as m3/mole; R is the gas constant; and T is the temperature in K. In one aspect, the gas constant R=0.0821 liter·atmosphere·mole−1·K−1. Some van der Waals constants for some substances are noted in Table 1:

TABLE 1
Critical Critical
a b Pressure Temperature
Substance (J · m3/mole2) (m3/mole) (MPa) (K)
Air 0.1358 3.64 × 10−5 3.77 133
Carbon 0.3643 4.27 × 10−5 7.39 304.2
Dioxide
(CO2)
Nitrogen 0.1361 3.85 × 10−5 3.39 126.2
(N2)
Hydrogen 0.0247 2.65 × 10−5 1.30 33.2
(H2)
Propane 0.5507 3.04 × 10−5 22.09 647.3
(C3H8)
Ethylene 0.4233 3.73 × 10−5 11.28 4.6
(C2H4)
Propylene 0.00341 2.34 × 10−5 0.23 5.2
(C3H6)
Methanol 1.078 9.98 × 10−5 4.12 385
(CH3OH)

The van der Waals Equation of State is a second order approximation of the equation of state of a gas that may be used to determine the desired volume of phase change fluid for use in pressurized gas chamber 120. Generally, the van der Waals equation works well for temperatures that are slightly above the critical temperature of a substance. In addition, to these equations, other real gas equations may be used that are commonly known to those skilled in the art.

Another means of determining the volume of phase change fluid to pressurize in the pressurized gas chamber 120 is a pressure-temperature phase diagram for a particular fluid, element, substance or mixture thereof. For example, referring to FIG. 5, a pressure-temperature phase diagram 470 for a phase change fluid is shown. The pressure-temperature phase diagram 470 shows a boiling line that is the line that extends from the critical point 480 to the triple point 472, which separates the gas phase or region 482 from the liquid phase or region 476. At the critical point 480, the densities of the equilibrium liquid phase 476 and saturated gas phase 482 become equal resulting in a supercritical phase 478. As an example, the critical point 480 for the phase change fluid of carbon dioxide occurs at approximately 304.1 K and 73.8 bars.

In the supercritical phase 478, the phase change fluid is above its critical temperature and critical pressure. The critical point 480 represent the highest temperature and pressure at which the phase change fluid, or any supercritical fluid for that matter, can exist as a gas and liquid in equilibrium. Thus, above the critical temperature a gas, such as carbon dioxide, cannot be liquefied by pressure. Nevertheless, at extremely high pressures the fluid can solidify, as shown in FIG. 5. It is noted that the pressures within the pressurized gas chamber 120 downhole in the wellbore 4 are to be less than that required to solidify the phase change fluid. Generally, the inherent characteristics and phase changes near the critical point 480 show large gradients with pressure near the critical point 480. At higher temperatures, the phase change fluid behaves like a gas at high pressure as can be seen in FIG. 5.

As can be seen from the pressure-temperature phase diagram 470, a desired amount of pressure of phase change fluid can be produced for a given temperature downhole in the wellbore 4. It can be seen that in the supercritical phase 478 the higher the temperature of the phase change fluid the significantly higher the pressure it produces in the pressurized gas chamber 120, thus enabling the fluid spring operation of the present invention.

In one embodiment, the phase change fluid is carbon dioxide. In another embodiment, the phase change fluid may be another fluid, element, substance or mixture thereof include, but not limited to, water, ammonia, diethyl ether, methane, ethane, propane, ethylene, propylene, methanol, ethanol, Freon and acetone. The following properties of these substances are noted in Table 2:

TABLE 2
Molecular Critical Critical
Weight Temperature Pressure Mpa Density
Substance (g/mol) (K) (Atm) (g/cm3)
Carbon 44.01 304.1 7.38 (72.8) 0.469
Dioxide (CO2)
Water (H2O) 18.02 647.3 22.12 (218.3) 0.348
Methane 16.04 190.4 4.60 (45.4) 0.162
(CH4)
Ethane (C2H6) 30.07 305.3 4.87 (47.1) 0.203
Propane 44.09 369.8 4.25 (41.9) 0.217
(C3H8)
Ethylene 28.05 282.4 5.04 (49.7) 0.215
(C2H4)
Propylene 42.08 364.9 4.60 (45.4) 0.232
(C3H6)
Methanol 32.04 512.6 8.09 (79.8) 0.272
(CH3OH)
Ethanol 46.07 513.9 6.14 (60.6) 0.276
(C2H5OH)
Acetone 58.08 508.1 4.70 (46.4) 0.278
(C3H6O)

For making the determination of the volume of phase change fluid to have in the pressurized gas chamber 120, it is important to know several factors relating to the downhole conditions in the wellbore 4. For example, it is important to acquire what the approximate downhole temperature is where the phase change fluid spring 450 will operate. This temperature can be acquired by any means as is commonly known to those skilled in the art, such as by downhole temperature gauges and the like. In addition, a knowledge of the density and depth of the fluid within the annulus for determining the hydrostatic pressure of the downhole wellbore 4. The weight and depth of the mud used in the annulus may be used to make this determination, for example. Further, the amount of pressure to be cycled on the annulus fluid by the pump 24 and control conduit 26 is important to making this determination as well.

The following examples are provided to further illustrate the preferred embodiments of the present invention.

EXAMPLE 1

It is determined that a testing tool with phase change fluid spring 50 will be used in a particular downhole environment using a phase change fluid of carbon dioxide. The hydrostatic pressure in the annulus may be determined by the weight and/or density of the mud and the depth of the mud at which the testing toot with phase change fluid spring 50 will be used. For example, if it is determined that the hydrostatic pressure in the unpressurized annulus is approximately 10,000 psi, then the phase change fluid in the pressurized gas chamber 120 should sufficiently exceed the hydrostatic such as a pressure of at least 10,500 psi pressure. As described above, energy is stored in the phase change fluid spring 450 by compressing the phase change fluid by pressurizing the annulus using the pump 24 via the control conduit 26. In this example, the amount of phase change fluid to be charged into chamber 120 at the surface can be determined based upon the required downhole volume using the ideal gas law.

In this example, the desired downhole gas volume (V) is 8 liters. Based upon the desired downhole volume, the downhole temperature and the downhole pressures, the liquid volume of the carbon dioxide to be charged into the chamber 120 at surface temperature must be determined. In this example, a downhole temperature of approximately 500° C. or 773.15 K has been determined using temperature gauges or sensors as commonly known in the art. The hydrostatic pressure is approximately 10,000 psi or 680.5 atmospheres. The gas constant R=0.0821 liter·atmosphere·mole−1·K−1. Using these values, it can be determined that approximately 85.8 moles of carbon dioxide must be charged as a liquid into chamber 120.

As stated above, the critical point for carbon dioxide occurs at 304.1 K (31.1° C. or 88° F.) and 73.8 bars (1,070 psi). If the charging of carbon dioxide into the chamber 120 at the surface is to take place at a temperature of about 88° F., then the pressure on the liquid carbon dioxide should be maintained above 1,070 psi, for example 1,500 psi.

Liquid carbon dioxide has a density of approximately 1.03 gms/ml, thus 85.8 moles of liquid carbon dioxide, which has a molecular mass of 44.0095, will weight approximately 3,432.8 gms. Using the density of liquid carbon dioxide, this weight of carbon dioxide will occupy approximately 3,332 mls or 3.33 liters. Thus, second fluid 462 should be maintained at a suitable pressure to control the rate and volume of liquid carbon dioxide entering chamber 120. When the desired volume of liquid carbon dioxide has been charged into chamber 120, lateral bore 108 may be closed and phase change fluid spring 450 may be disconnected from phase change fluid source 454 and fluid reservoir 462. In this manner, the required amount of phase change fluid can be charged into chamber 120 at a pressure significantly lower than the downhole pressure at which it will provide the energy storage capability. In addition, charging the chamber at the lower surface pressure provides for a high degree of safety during the charging and handling of the phase change fluid spring of the present invention.

EXAMPLE 2

The desired downhole volume (V) of the phase change fluid, in this case carbon dioxide is 16 liters. The hydrostatic pressure at the desired depth is approximately 20,000 psi. The downhole temperature at the desired depth is approximately 250° C. or 523.15 K. The ideal gas law, PV=nRT, may be used to determines the required liquid volume of carbon dioxide at the surface. Using the gas constant of R=0.0821 liter·atmosphere·mole−1·K−1, it can be determined that approximately 253.49 moles of carbon dioxide are required. Charging the chamber 120 at the surface at a temperature of about 88° F. will require a pressure of at least 1,070 psi and preferably 1,500 psi to maintain the carbon dioxide in a liquid state. Liquid carbon dioxide has a density of approximately 1.03 gms/ml, thus 253.49 moles of liquid carbon dioxide, which has a molecular mass of 44.0095, will weight approximately 11,155 gms. Using the density of liquid carbon dioxide, this weight of carbon dioxide will occupy approximately 11,155 mls or 11.16 liters.

EXAMPLE 3

In another example, the amount of phase change fluid that is charged into the phase change fluid spring 450 may determined by weight. For example, the change in weight of the phase change fluid source 454 or the phase change fluid spring 450 may be monitored to determine if the required amount of phase change fluid has been charged into the chamber 120.

EXAMPLE 4

In yet another example, a phase change fluid spring 450 may be pressurized with one or more containers having a known volume of phase change fluid contained therein. For instance, if it is determined that approximately 5 liters of phase change fluid in a liquid state are desired, then this volume may be charged in the phase change fluid spring 450 using 10 containers or vessels that each contain approximately 500 mls of phase change fluid.

The present invention is described with respect to preferred embodiments, but is not limited to those described. For example, any substance may be used that is in a first phase, such as a liquid phase, at the surface at first a pressure and at a second phase, such as a gas phase or supercritical phase, downhole in the wellbore 4. Alternatively, the testing tool with phase change fluid spring 50 might be programmed to effect modes of operation other than those disclosed with respect to the preferred embodiments described herein. It will be readily apparent to one of ordinary skill in the art that numerous such modifications may be made to the invention without departing from the spirit and scope of it as claimed.

Referenced by
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US7866400 *Feb 28, 2008Jan 11, 2011Halliburton Energy Services, Inc.Phase-controlled well flow control and associated methods
US8096362Dec 6, 2010Jan 17, 2012Halliburton Energy Services, Inc.Phase-controlled well flow control and associated methods
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Classifications
U.S. Classification166/373, 166/319
International ClassificationE21B34/08
Cooperative ClassificationE21B23/04
European ClassificationE21B23/04
Legal Events
DateCodeEventDescription
Jun 20, 2008ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:WRIGHT, ADAM D.;NORMAN, LEWIS;SCHULTZ, ROGER L.;REEL/FRAME:021130/0151;SIGNING DATES FROM 20080606 TO 20080612