EP1257730B1

EP1257730B1 - Apparatus and method for controlling well fluid sample pressure

Info

Publication number: EP1257730B1
Application number: EP00959416A
Authority: EP
Inventors: Paul Andrew Reinhardt
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2000-02-25
Filing date: 2000-08-25
Publication date: 2008-12-03
Anticipated expiration: 2020-08-25
Also published as: RU2244123C2; DE60041005D1; RU2002125501A; EP1257730A1; CA2401375A1; CA2401375C; WO2001063093A1

Description

The present invention relates to the art of earth boring and the collection of formation fluid samples from a wellbore. More particularly, the invention relates to methods and apparatus for collecting a deep well formation sample and preserving the in situ constituency of the sample upon surface retrieval.
Earth formation fluids in a hydrocarbon producing well typically comprise a mixture of oil, gas, and water. The pressure, temperature and volume of formation fluids control the phase relation of these constituents. In a subsurface formation, high well fluid pressures often entrain gas within the oil above the bubble point pressure. When the pressure is reduced, the entrained or dissolved gaseous compounds separate from the liquid phase sample. The accurate measure of pressure, temperature, and formation fluid composition from a particular well affects the commercial interest in producing fluids available from the well. The data also provides information regarding procedures for maximizing the completion and production of the respective hydrocarbon reservoir.
Certain techniques analyze the well fluids downhole in the wellbore. United States Patent No. 5,361,839 to Griffith et al. (1993 ) disclosed a transducer for generating an output representative of fluid sample characteristics downhole in a wellbore. United States Patent No. 5,329,811 to Schultz et al. (I 994 ) disclosed an apparatus and method for assessing pressure and volume data for a downhole well fluid sample.
Other techniques capture a well fluid sample for retrieval to the surface. United States Patent No. 4,5 83,595 to Czenichow et al. (1986 ) disclosed a piston actuated mechanism for capturing a well fluid sample. United States Patent No. 4,721,157 to Berzin ( 1988 ) disclosed a shifting valve sleeve for capturing a well fluid sample in a chamber. United States Patent No. 4,766,955 to Petermann ( 1988 ) disclosed a piston engaged with a control valve for capturing a well fluid sample, and United States Patent No. 4,903,765 to Zunkel ( 1990 ) disclosed a time delayed well fluid sampler. United States Patent No. 5,009,100 to Gruber et al. (1991 ) disclosed a wireline sampler for collecting a well fluid sample from a selected wellbore depth, United States Patent No. 5,240,072 to Schultz et al. (1993 ) disclosed a multiple sample annulus pressure responsive sampler for permitting well fluid sample collection at different time and depth intervals, and United States Patent No. 5,322,120 to Be et al. (1994 ) disclosed an electrically actuated hydraulic system for collecting well fluid samples deep in a wellbore.
Temperature downhole in a deep wellbore often exceed 300 degrees F (149°C). When a hot formation fluid sample is retrieved to the surface at 70 degrees F (21°C) the resulting drop in temperature causes the formation fluid sample to contract. If the volume of the sample is unchanged, such contraction substantially reduces the sample pressure. A pressure drop changes in the situ formation fluid parameters, and can permit phase separation between liquids and gases entrained within the formation fluid sample. Phase separation significantly changes the formation fluid characteristics, and reduces the ability to evaluate the actual properties of the formation fluid.
To overcome this limitation, various techniques have been developed to maintain pressure of the formation fluid sample. United States Patent No. 5,337,822 to Massie et al. (1994 ) pressurized a formation fluid sample with a hydraulically driven piston powered by a high pressure gas. Similarly, United States Patent No. 5,662,166 to Shammai ( 1997 ) used a pressurized gas to charge the formation fluid sample. United States Patent Nos. 5,303,775 ( 1994 ) and 5,377,755 ( 1995) to Michaels et al . disclosed a bi-directional, positive displacement pump for increasing the formation fluid sample pressure above the bubble point so that subsequent cooling did not reduce the fluid pressure below the bubble point. Similarily EP 0903464 discloses an apparatus for collecting a fluid sample without flashing of vapour in the liquid and which retains the fluid sample in a "supercharged" condition.
Existing techniques for maintaining the sample formation pressure are limited by many factors. Pretension or compression springs are not suitable because the required compression forces require extremely large springs. Shear mechanisms are inflexible and do not easily permit multiple sample gathering at different locations within the wellbore. Gas charges can lead to explosive decompression of seals and sample contamination. Gas pressurization systems require complicated systems including tanks, valves and regulators which are expensive, occupy space in the narrow confines of a wellbore, and require maintenance and repair. Electrical or hydraulic pumps require surface control and have similar limitations.
Accordingly, there is a need for an improved system capable of compensating for hydrostatic wellbore pressure loss so that a formation fluid sample can be retrieved to the well surface at substantially the original formation pressure. The system should be reliable and should be capable of collecting the samples from the different locations within a wellbore.
The present invention provides an apparatus as claimed in claim 1 and method as claimed in claim 15 for controlling the pressure of a pressurized formation fluid sample collected from a wellbore.
The apparatus of the invention comprises a housing having a hollow interior. A piston within the housing interior defines a fluid sample chamber wherein the piston is moveable within the housing interior to selectively change the fluid sample chamber volume. The piston, preferable a compound piston preferably comprises an outer sleeve and an inner sleeve moveable relative to the outer sleeve. However, movement of the inner sleeve relative to the outer sleeve is unidirectional. A pump, preferably an external pump, extracts formation fluid for delivery under pressure into the fluid sample chamber. A positioned opened valve permits pressurized wellbore fluid to move said piston for pressurizing the fluid sample within the fluid sample chamber so that the fluid sample remains pressurized when the fluid sample is moved to the Well surface.
In a preferred embodiment, the method of the invention is practiced by lowering a housing into a wellbore. The compound piston is displaced within the sample chamber by formation fluid delivered by the external pump. When the sample chamber has filled, a valve is opened to introduce wellbore fluid at hydrostatic wellbore pressure against the piston to move the piston for pressurizing the well fluid sample within the fluid sample chamber. By means of piston area differential, force on a inner sleeve of the compound piston is unbalanced to compress the fluid sample by a volumetric reduction. The reduced volume is secured by mechanically securing the relative positions ofthe compound piston against the sample chamber.
Various embodiments of the present invention will now be described, by way of example only and with reference to the accompanying drawings in wich:
when considered

FIG. 1 is a schematic earth section illustrating a preferred embodiment of the invention operating environment;
FIG. 2 is a schematic of a preferred embodiment of the invention in operative assembly with cooperatively supporting tools;
FIG. 3 is a schematic of a representative formation fluid extraction and delivery system;
FIG. 4 is an isometric view of a sampling tank magazine;
FIG. 5 is an isometric view of a preferred embodiment of the present invention;
FIG. 6 is an axially sectioned isometric view of a preferred embodiment of the invention;
FIG. 7 is a sectioned detail of the sample inlet end of a preferred embodiment of the invention;
FIG. 8 is a sectioned detail of the sample chamber portion of a preferred embodiment of the invention assembly;
FIG. 9 is a sectioned detail ofthe hydrostatic wellbore pressure end of the compound piston;
FIG. 10 is an axially sectioned isometric view of a preferred embodiment the invention in the course of receiving a sample of formation fluid;
FIG. 11 is a sectioned detail of the compound piston position for wellbore fluid entry;
FIG. 12 is a sectioned detail of relative axial displacement between the elements of the compound piston;
FIG. 13 is an axially sectioned view of a preferred embodiment of the invention in the course of sample extraction; and,
FIG. 14 is an orthographic axial section of a preferred embodiment of the invention.

FIG. 1 schematically represents a cross-section of earth 10 along the length of a wellbore penetration 11. Usually, the wellbore will be at least partially filled with a mixture of liquids including water, drilling fluid, and formation fluids that are indigenous to the earth formations penetrated by the wellbore. Hereinafter, such fluid mixtures are referred to as "wellbore fluids". The term "formation fluid" hereinafter refers to a specific formation fluid exclusive of any substantial mixture or contamination by fluids not naturally present in the specific formation.
Suspended within the wellbore 11 at the bottom end of a wireline 12 is a formation fluid sampling tool 20. The wireline 12 is often carried over a pulley 13 supported by a derrick 14. Wireline deployment and retrieval is performed by a powered winch carried by a service truck 15, for example.
Pursuant to the present invention, a preferred embodiment of a sampling tool 20 is schematically illustrated by FIG. 2 . Preferably, such sampling tools are a serial assembly of several tool segments that are joined end-to-end by the threaded sleeves of mutual compression unions 23. An assembly of tool segments appropriate for the present invention may include a hydraulic power unit 21 and a formation fluid extractor 22. Below the extractor 22, a large displacement volume motor/pump unit 24 is provided for line purging. Below the large volume pump is a similar motor/pump unit 25 having a smaller displacement volume that is quantitatively monitored as described more expansively with respect to FIG. 3 . Ordinarily, one or more tank magazine sections 26 are assembled below the small volume pump. Each magazine section 26 may have three or more fluid sample tanks 30.
The formation fluid extractor 22 comprises an extensible suction probe 27 that is opposed by borewall feet 28. Both, the suction probe 27 and the opposing feet 28 are hydraulically extensible to firmly engage the wellbore walls. Construction and operational details of the fluid extraction tool 22 are more expansively described by U.S. Patent No. 5,303,775 .
Operation of the tool is fundamentally powered by electricity delivered from the service truck 15 along the wireline 12 to the hydraulic power supply unit 21. With respect to FIG. 3 , the constituency of the hydraulic power supply unit 21 comprises an A.C. motor 32 coupled to drive a positive displacement, hydraulic power pump 34. The hydraulic power pump energizes a closed loops hydraulic circuit 36. The hydraulic circuit is controlled, by a solenoid actuated 4- way valve 47, for example, to drive the motor section 42 of an integrated, positive displacement, pump/motor unit 25. The pump portion 44 of the pump/motor unit 25 is monitored by means such as a rod position sensor 46, for example, to report the pump displacement volume. Formation fluid drawn through the suction probe 27, is directed by a solenoid controlled valve 48 to alternate chambers of the pump 44 and to a tank distributor 49. By this route, sample volumes of selected formation fluid are extracted directly from respective in situ formations and delivered to designated sample chambers among the several sample tank tools 30.
As sub-steps in the formation fluid extraction procedure of a perferred embodiment of the present invention, the large volume motor/pump unit 24 is employed to purge the -formation fluid flow lines between the suction probe 27 and the small volume pump 25. Since these sub-steps do not require accurate volumetric data, measurement of the pump displacement volume is not required. Otherwise, the motor/pump unit 24 may be substantially the same as motor/pump unit 25 except for the preference that the pump of unit 24 have a greater displacement volume capacity.
A representative magazine section 26 is illustrated by FIG. 4 to include a fluted, cylinder 50. Preferably, the cylinder 50 is fabricated to accommodate three or four tanks 30. Each tank 30 is operatively loaded into a respective alcove 52 with a bayonet-stab fit. Two or more cylinders 50 are joined by an internally threaded sleeve 23 that is axially secured to one end of one cylinder but freely rotatable about the cylinder axis. The sleeve 23 is turned upon the external threads of a mating joint boss 52 to draw the boss into a compression sealed juncture therebetween whereby the fluid flow conduits 54 drilled into the end of each boss 52 are continuously sealed across the joint.
FiGs. 5 , 6 and 7 illustrate each tank 30 as comprising a cylindrical pressure housing 60 that is delineated at opposite ends by cylinder headwalls. The bottom-end headwall comprises a valve sub-assembly 62 having a socket boss 63 and a fluid conduit nipple 66 projecting axially therefrom. A conduit 68 within the nipple 66 is selectively connected by a respective conduit 54 to the tank distributor 49 and, ultimately, to the suction probe 27 of the formation fluid extractor 22. Fluid flow within the conduit 68 is rectified by a check valve 69. Within the valve sub-assembly 62 is a formation fluid flow path 74 between the conduit 68 and a formation fluid reservoir internally of the pressure housing 60. A solenoid actuated shut-off valve 76 is disposed to selectively open and close the channel of flow path 74. As best seen from the isometric detail of FIG. 7 , a bleed valve 78 selectively closes a shunt conduit 79 that junctions with the flow path 74.
Referring again to the axial half-section of FIG. 6 , the pressure housing top-end headwall comprises a sub 64 having a fluid inlet conduit 70 that connects the interior bore 80 of the pressure housing 60 with a threaded tubing nipple socket 72. The conduit 70 is a normally open fluid flow path between the interior bore 80 and the in situ wellbore environment. Within the interior bore 80 of the pressure housing 60 is a traveling trap sub-assembly 82 that comprises the coaxial assembly of an inner traveling/locking sleeve 86 within an outer traveling sleeve 84 as shown by FIG.8 . Unitized with the outer traveling sleeve 84 by a retaining bolt 88 as shown by FIG. 9 , is a locking piston rod 90. A fluid channel 92 along the length of the rod 90 openly communicates the inner face 96 of a floating piston 94 with the open well bore conduit 70. The floating piston 94 is axially confined within the inner bore of the inner traveling/locking sleeve 86 by a retaining ring 98. A mixing ball 99 is placed within the sample (formation fluid) receiving chamber 95 that is geometrically defined as that variable volume within the interior bore 80 of pressure housing 60 between the valve sub-assembly 62 and the end area of the traveling trap sub-assembly 82.
A body lock ring 100 having internal barb rings 102 and external barb rings 104 selectively connects the rod 90 to the inner traveling/locking sleeve 86. The selective connection of the barbed lock ring 100 permits the sleeve 86 to move coaxially along the rod 90 from the piston 84 but prohibits any reversal of that movement.
Another construction detall of the inner traveling/locking sleeve 86 is the sealed partition 122 between the opposite ends of the sleeve 86. The chamber 124 created between the partition 122 and the piston head 106 of the rod 90 is sealed to the atmospheric pressure present in the chamber at the time of assembly.
The body lock ring 100 between the locking piston rod 90 and the inner bore wall of the inner traveling/locking sleeve 86 above the partition 122 does not provide a fluid pressure barrier. Consequently, the chamber 126 between the partition 122 and the body lock ring 100 functions at the same fluid pressure as the wellbore fluid flood chamber 120 when the flood valve 110 is opened.
Still with respect to FIG.9, the base of the floating piston/sleeve 84 includes a flood valve 110 having a pintle 112 biased by a spring 114 against a seal seat 116. The pintle includes a stem 118 that projects beyond the end plane of the floating piston /sleeve 84. When the end plane of the floating piston/sleeve 84 is pressed against the inner face of the top sub 64 ( FIG. 11 ), the pintle 112 is displaced from engagement with the seal seat 116 to admit wellbore fluid into the flood chamber 120 as is illustrated by FIGS. 11 and 12 . The flood chamber 120 is geometrically defined as the variable volume bounded by the annular space between the outer perimeter of the rod 90 and the inner bore 85 of the outer traveling sleeve 84.
Preparation of the sample tanks 30 prior to downhole deployment includes the closure of bleed valve 78 and the opening of shut-off valve 76. Under the power and control of instrumentation carried by the service truck 15, the sampling tool is located downhole at the desired sample acquisition location. When located, the hydraulic power unit 21 is engaged by remote control from the service truck 15. Hydraulic power from the unit 21 is directed to the formation fluid extractor unit 22 for borewall engagement of the formation fluid suction probe 27 and the borewall feet 28. The suction probe 27 provides an isolated, direct fluid flow channel for substantially pure formation fluid. Such formation fluid flow into the suction probe 27 is first induced by the suction of large volume pump 24 which is driven by the hydraulic power unit 21. The large volume pump 24 is operated for a predetermined period of time to flush the sample distribution conduits of contaminated wellbore fluids with formation fluid drawn through suction probe 27. When the predetermined line flushing interval has concluded, hydraulic power is switched from the large volume pump 24 to the small volume piston pump 25. Referring to FIG. 3 , formation fluid drawn from the suction probe 27 by the pump 25 is shuttled by 4-way valve 48 into successively opposite chambers 44. Simultaneously, the valve 48 directs discharge from the chambers to a multiple port rotary valve 49, for example, which further directs the formation fluid on to the desired sample tank 30.
Formation fluid enters the tank 30 through the nipple conduit 68 and is routed past the check valve 69 and along the flow path 74 into the sample receiving chamber 95. The tank shut-off valve 76 was opened before the tank was lowered into the wellbore. Pressure of the pumped formation fluid in the receiving chamber 95 displaces both, the outer traveling sleeve 84 and the inner traveling/locking sleeve 86, against the standing wellbore pressure in the interior bore 80 of pressure housing 60 as shown by FIG. 10 . When the pressure of the formation fluid sample within the formation fluid sample chamber 95 reaches the boost pressure limit of pump 25, high pressure check valve closes to trap the sample of formation fluid within the sample chamber 30 and passage 32.
Also, when the sample receiving chamber 95 is full, the base plane of the outer traveling sleeve 84 will engage the inside face of the top sub 64. Thereby, the stem 118 is axially displaced to open the flood valve 110. Internal conduits within the outer traveling sleeve 84 direct wellbore fluid into the flood chamber 120. The wellbore pressure in the flood chamber 120 bears against the inner traveling/locking sleeve 84 over the cross-sectional area of the flood chamber 120 annulus.
Opposing the flood chamber force on the traveling/locking sleeve 86 are two pressure sources. One source is the formation fluid pressure in the sample chamber 95 bearing on the annular end section of the traveling/locking sleeve 86 as was provided by the small volume pump unit 25. The other pressure opposing the flood chamber pressure is the closed atmosphere chamber 124 acting on the area of the annular partition 122. Initially, the force balance on the traveling/locking sleeve 86 favors the flood chamber side to press the annular end of the sleeve 86 into the sample chamber 95. Since the liquid formation fluid is substantially incompressible, intrusion of the solid structure of the sleeve 86 annulus into the sample chamber volume exponentially increases the pressure in the sample chamber until a final force equilibrium is achieved. Nevertheless, at the pressures of this environment, measurable liquid compression may be achieved.
This axial movement ofthe innertraveling/locking sleeve 86 relative to the outer sleeve 84 also translates to the piston rod 90 which is secured to the outer sleeve 84 via the retaining bolt 88. Consequently, the sleeve 86 partition 122 is displaced toward the piston head 106 to compress the gaseous atmosphere of chamber 124 thereby adding to the equilibrium forces.
Due to the internal and external barb rings 102 and 104 respective to the body lock ring 100, movement of the piston 90 relative to the inner traveling sleeve 86 is rectified to maintain this volumetric invasion of the structure 86 into the sample chamber volume.
By compressing the volume of the formation fluid sample, the fluid sample pressure is greatly above the wellbore pressure. Although this greatly increased in situ pressure declines when the confined formation sample is removed from the wellbore, the operative components may be designed so that when the collected formation sample is removed from the well, the sample pressure does not decline below the bubble point of entrained or dissolved gas. Movement of the inner traveling/locking sleeve 86 further compresses the collected formation fluid sample above the boost capability of the pump 25. Such compression continues until the desired boost ratio is accomplished.
For example, a down hole fluid sample can have a hydrostatic wellbore pressure of 10,000 psi (6.9x10⁷ Pa). The typical compressibility for such a fluid is 5X10^-6 so that a volume decrease of only eight percent would raise the fluid sample pressure by 16,000 psi (1.1x10⁸ Pa) to 26,000 psi (1.8x10⁸ Pa) for a boost ratio of 2.6 to 1.0. When the magazine section 26 and the collected formation fluid sample is raised to the surface of well bore 11, the formation fluid sample temperature will cool, thereby returning the formation fluid sample pressure toward the original pressure of 10,000 psi (6.9x10⁷ Pa). If the downhole fluid temperature is 270°F (132°C) and the wellbore 11 surface temperature is 70°F (21°C), the resulting 200°F (111°C) drop in temperature will lower the fluid sample pressure by approximately 15,300 psi (1.1×10⁸ Pa) in a fixed volume, thereby resulting in a surface fluid sample pressure of approximately 10,700 psi (7.4x10⁷ Pa).
To hold the volume of fluid sample chamber 95 constant as the magazine 26 is removed from the wellbore 11, inner traveling/locking sleeve 86 is fixed relative to outer traveling sleeve 84 during retrieval of the magazine 26. The invention accomplishes the fixed relationship by means of the body lock ring 100. This mechanism permits additional boost to be added to the formation fluid sample pressure within the sample chamber 96 as a proportionality of the in situ wellbore pressure. For example, the magazine section 26 may subsequently be lowered to additional depths within a wellbore 11 where the hydrostatic pressure is greater than a prior sample extraction. The hydrostatic wellbore pressure increase is transmitted through flood valve 112 into flood chamber 120 to further move the inner traveling/locking sleeve 86 and to further compress the formation fluid sample within the sample chamber 95 to a greater pressure. Such pressure boost can be accomplished quickly and magazine 26 removed to the surface of wellbore 11 before a significant amount of heat from the additional wellbore depth is transferred to the previously collected formation fluid sample.
At the surface of wellbore 11, tank shut-off valve 76 is closed to trap the formation fluid sample. Thereafter, bleed valve 78 may be opened to relieve the fluid pressure in the flow passage between tank shut-off valve 76 and the high pressure check valve 69. This pressure release provides a positive indication of fluid pressure and facilitates removal of a tank 30 from a magazine 26.
Fig. 13 illustrates one technique for removing the formation fluid sample under pressure from within fluid sample chamber 95. Tank 30 is connected to a pressure source 130 engaged with aperture 132 through top sub 64. Pressure from the pressure source 130 is introduced until the inverse of the boost ratio times the expected pressure within fluid sample chamber 95 is reached. For a fluid sample pressure of 10,000 psi (6.9x10⁷ Pa) the extraction pressure required would be: $1 / 2.6 X 10, 000 = 3, 850 psi (2.7 x 10^{7} Pa)$

After the inverse boost ratio is reached, shut-off valve 76 is cracked open and the formation fluid sample is permitted to pass through passage 74 into an attached receiver line 140. The reverse boost pressure can be increased to displace the collected formation fluid sample until the sleeve edge of the inner traveling/locking sleeve 86 bottoms out against the valve sub 62. Continued extraction fluid from the pressure source 130 displaces the outer traveling sleeve 84 relative to the inner sleeve 86. Hence, the piston head 106 engages the floating piston 94 to sweep most of the formation fluid sample from the chamber 95. The only volume within the chamber 95 not removed by the extraction pressure is found in an annular space between the outer traveling sleeve 84 and the valve sub 62. The components of tank 30 can be dissembled and reset for another use.
In summary, the invention permits multiple tanks 30 to be lowered in the same operation so that different zones within wellbore 11 can be sampled. Each tank can be selectively operated to collect different samples at different pressures and to compress each sample to different rates exceeding the bubble point for gas within the sample. Operating costs are significantly reduced because less rig time is required to sample multiple zones. The invention prevents the pressure within each fluid sample from being reduced below the bubble point therefore delivering each fluid sample to the wellbore surface in substantially the same pressure state as the downhole sampling state. The invention accomplishes this function without requiring expanding gases, large springs and complicated mechanical systems. The fluid sample is collected under pressure and additional pressure is added with a force exerted by the downhole hydrostatic pressure.
Although the invention has been described in terms of certain preferred embodiments, it will become apparent to those of ordinary skill in the art that modifications and improvements can be made to the inventive concepts herein without departing from the scope of the invention as set forth in the accompanying claims. The embodiments shown herein are merely illustrative of the inventive concepts and should not be interpreted as limiting the scope of the invention.

Claims

An apparatus for controlling the pressure of a pressurized formation fluid sample collected downhole in a well, comprising:
a housing (60) having a hollow interior;

a piston (90, 94) within said housing interior for defining a fluid sample chamber (95), wherein said piston (90, 94) is moveable within said housing interior to selectively change said fluid sample chamber volume;
characterised by further comprising:
a pump (25) for introducing a formation fluid sample under pressure into said chamber (95); and

a valve (110) for permitting pressurized wellbore fluid to move said piston (90, 94), wherein said piston movement pressurizes the fluid sample within said fluid sample chamber (95) so that the fluid sample remains pressurized when the fluid sample is moved to the well surface.
An apparatus as recited in claim 1, wherein said valve (110) is attached to said piston (90, 94).
An apparatus as recited in claim 1 or 2, further comprising a check valve (69) engaged between said pump (25) and said fluid sample chamber (95) for preventing said piston (90, 94) from forcing the fluid sample toward said pump (25).
An apparatus as recited in claim 1, 2 or 3, further comprising a tank shut-off valve (76) engaged between said pump (25) and said fluid sample chamber (95) for selectively permitting said fluid sample chamber (95) to be pressure isolated from said pump (25).
An apparatus as recited in any preceding claim, further comprising a lock (100) for retaining said piston (90, 94) fixed relative to said housing (60) to maintain the volume of said fluid sample chamber (95).
An apparatus as recited in any preceding claim, wherein said piston (90, 94) includes an outer sleeve (84) and an inner sleeve (86) moveable relative to said outer sleeve (84), and wherein said valve (110) is capable of permitting the pressurized wellbore fluid to contact said inner sleeve (86) so as to move said inner sleeve (86) relative to said outer sleeve (84) and thereby pressurize the fluid sample.
An apparatus as recited in claim 6, further comprising a lock (110) for retaining said inner sleeve (86) fixed relative to said outer sleeve (84) to maintain the volume of said fluid sample chamber (95).
An apparatus as recited in claim 6 or 7, further comprising a flood chamber (120) between said inner sleeve (86) and said outer sleeve (84) for receiving the pressurized wellbore fluid so that the wellbore fluid exerts a differential pressure against said inner sleeve (86) to move said inner sleeve (86) relative to said outer sleeve (84).
An apparatus as recited in claim 6, 7 or 8, further comprising an atmospheric chamber (124) between said inner sleeve (86) and said outer sleeve (84) which initially has a pressure lower than the hydrostatic pressure and which is reduced in volume as said inner sleeve (86) moves relative to said outer sleeve (84).
An apparatus as recited in any preceding claim, wherein said piston (90, 94) comprises an outer sleeve (84) and an inner sleeve (86) moveable relative to said outer sleeve (84), and wherein said apparatus further comprises a retainer means (88) for retaining said outer sleeve (84) relative to said housing (60).
An apparatus as recited in any preceding claim, wherein said piston comprises an outer sleeve (84) and an inner sleeve (86) moveable relative to said outer sleeve (84), and wherein said apparatus further comprises a lock (100) for retaining said inner sleeve (86) stationary relative to said housing (60).
An apparatus as recited in any preceding claim, further comprising a valve (69) for selectively blocking fluid communication between said pump (25) and said fluid sample chamber (95).
An apparatus as recited in claim 12, wherein said valve (69) comprises a check valve.
An apparatus as recited in any preceding claim, further comprising a second housing and a second piston within said second housing which define a second fluid sample chamber that is engaged with said pump (25) for selectively pressurizing a second formation fluid sample to a different pressure than the fluid pressure within the first fluid sample chamber (95).
A method for controlling the pressure of a pressurized formation fluid sample from a wellbore, comprising:
lowering a downhole tool (20) into the wellbore, wherein said downhole tool (20) comprises a housing (60) and a piston (90, 94) that is moveable within a hollow interior of the housing (60) to define a fluid sample chamber (95);

pumping formation fluid into said fluid sample chamber (95) to collect a formation fluid sample;

operating a valve (110) to introduce wellbore fluid at a downhole hydrostatic pressure into contact with the piston (90, 94) so as to move said piston (90, 94) and thereby pressurize the fluid sample within said fluid sample chamber;

retaining the fluid sample within said fluid sample chamber (95) while compressing the fluid sample; and

withdrawing said downhole tool (20) to the well surface.
A method as recited in claim 15, further comprising the step of locking said piston (90, 94) relative to said housing (60) to fix the volume of the fluid sample within said fluid sample chamber (95) when the fluid sample reaches a selected pressure above the downhole hydrostatic pressure.
A method as recited in claim 15 or 16, further comprising the step of lowering said downhole tool (20) within the wellbore (11) so that a greater hydrostatic fluid pressure moves said piston (90, 94) to further compress the fluid sample before said downhole tool (20) is withdrawn to the well surface.
A method as recited in claim 15, 16 or 17, wherein said piston (90, 94) compresses the fluid sample to a pressure so that the fluid sample does not change phase when said downhole tool (20) is withdrawn to the well surface.
A method as recited in any of claims 15 to 18, further comprising the step of removing the fluid sample from said fluid sample chamber (95) while maintaining the pressure of the fluid sample above a selected pressure.
A method as recited in any of claims 15 to 19, further comprising the steps of:
moving said downhole tool (20) to a second location within the wellbore (11);

pumping a second formation fluid sample into a second fluid sample chamber;

compressing the second fluid sample; and

fixing the volume of the second fluid sample.
A method as recited in claim 20, wherein said downhole tool (20) comprises a second housing and a second piston that is moveable within a hollow interior of the second housing which defines the second fluid sample chamber.
A method as recited in claim 21, wherein the step of compressing the second fluid sample comprises operating a second valve to move said second piston.
A method as recited in claim 21 or 22, wherein the step of fixing the volume of the second fluid sample comprises locking said second piston relative to said second housing.
A method as recited in any of claims 20 to 23. wherein a second hydrostatic pressure at said second location compresses the second fluid sample to a pressure greater than the pressure of the first fluid sample.