FIELD OF THE INVENTION

This invention generally relates to a latching reciprocating valve assembly suitable typically for use with well testing tools In an open hole prior to lining of the hole with casing, however it is to be understood that the latching reciprocating valve assembly is of general applicability.

More particularly, the present invention relates to a latching reciprocating valve assembly capable of remaining in a closed mode of operation for all pressures of operation, and only moving to an open mode of operation once the pressure differential is reduced below a release pressure after having exceeding a predetermined minimum engagement pressure. The engagement pressure being greater than the release pressure.

More particularly, the latching reciprocating valve assembly of the present invention is of the type that may be used in a tool that is run into a core barrel on a wireline for testing or maintenance or the like of a well. The latching reciprocating valve assembly uses a sliding port collar and a sliding actuator to change between the closed mode and the open mode against a control spring mechanism.

In the field of well testing tools (also referred to as downhole testing tools) the latching reciprocating valve assembly of the present invention avoids the need to uee shear pins and a blow out plug in controlling the onset of operation of a valve for controlling the flow of well fluid at the completion of inflation of a bladder of an inflatable packer - such as, for example, in well testing, more particularly permeability testing (which is often also referred to as lugeon testing or packer testing).

The latching reciprocating valve assembly of the present invention is capable of use in injecting well fluid (typically water) into the formation surrounding the well - such as in permeability testing.

However, the latching reciprocating valve assembly of the present invention could be used in other applications where it is required to have a gentle actuation of a valve to open at a lower, release pressure, once a higher, engagement pressure, has been exceeded, so as to avoid sudden Inrush of high pressure well fluid that can result in damage to surrounding well formations and well mechanics.

As a proprietary term we refer to the latching reciprocating valve assembly of the present inventjon as an 'injection valve assembly".

TERMINOLOGY

In the fields of well and borehole technology there are a diversity of terminologies used. So as to avoid confusion the following specific terminology is used in the context of the present invention:

• "Casing" is a term used to refer to any type of pipe casing or the like, used in oil and gas or water well drilling operations. The term "well casing" is often used when referring to casing. The terms "inner casing' and 'outer casing" used herein relate to casing to the extent that they are made from casing;

• "Core barrel" is a term used to refer to a length of pipe for holding rock cores while they are being extracted from a drill hole;

• "Drill rods" is a term used to refer to long hollow drill rods used in drilling boreholes;

• "Elastomeric packer element" or "packer element" is a term used to refer to any type of generally tubular expandable element that may be inflated by settable or non- settabte slurry, liquid or gas, usually to fill an annular cavity.

• "Engagement pressure" s a term used to refer to a pressure differential above which the control valve assembly is activated so as to be to change its condition of operation once the pressure differential is reduced below the release pressure.

• "Inflation" is a term used to refer to inflation of an inflatable bladder of an inflatable packer.

• "Injection" is a term used to refer to injection of well fluid from the core barrel into the well, such as is used in permeability testing of formation to ascertain its production capacity.

• "Open hole" is a term used to refer to a well hole or borehole that has not been or is yet to be lined with a casing and cementitious material between the casing and the open hole.

• 'Open hole annukjs" is as term used to refer to the annular space between the

casing and the open hole.

• 'Pressure* in the context of the present invention is a term used to refer to differential pressure across a component of the latching reciprocating valve assembly. Unless otherwise specifically mentioned all references to pressure are references to differential pressures rather than absolute pressures.

• "Release pressure" is a term used to refer to a pressure differential below which the control valve assembly is able to move from a closed condition of operation to an open condition of operation. • "Testing" is a term used to refer to testing as it relates to well testing and tools for well testing and includes packer testing, lugeon testing and permeability testing (which are have substantially the same meaning).

• "Well" is a term used to refer to a hole bored in the ground. The term well is used interchangeably with bore and borehole.

• "Well fluid" is a term used to refer to any type of liquid or gas capable of use in

inflating an inflatable packer, and includes water, brine, gas (such as nitrogen) or the like non-settable fluid. Cement as a well fluid is specifically not for use in relation to the latching reciprocating valve assembly of the present invention, although other slurries such as drilling mud could be used.

BACKGROUND TO THE INVENTION

The traditional method of valve control for Inflatable packers uses a blow out plug assembly (for example US Patent 4,655,292 by Baker Oil Tools), whereby the blow out plug is retained by a shear pin. Pressure differentials above a predetermined pressure differential cause the shear pin to shear, the blow out plug is then blown out by the pressure differential and the valve changes its condition of operation from inflation of a bladder of an inflatable packer to injection of well fluid into formation surrounding the well, such as to test the permeability of the formation.

Such control valves have a number of disadvantages including that blow out plugs can result in hydraulic lock if used in impermeable formations. Also, shearing of the shear pins results in an abrupt change in the operating condition in prior art control valves which can lead to abrupt inrush of testing fluids and abrupt changes in pressure that can damage fragile formations and also lead to water hammer that can damage well mechanics. Further, different sizes and numbers of shear pins are required to achieve valve actuation at differing pressures. Still further, such prior art control valves require replacement of the shear pins and the associated blow out plugs In order to be reused. Still further, such prior art control valves require refurbishment in the field including disassembly, and replacement of shear pins and blow out plugs, which is typically a hostile environment not conducive to such refurbishment work. Still further, the pressure differential at which the pins shear can vary significantly - that is, it is not possible to accurately set or predict the pressure differential at which the shear pins will shear when in use.

Alternatively, it is also common in the prior art to rotate the drill rods about their longitudinal axis a number of times, such as, about 10 times, to change the mode of operation of an injection control valve. Rotating the drill rods overcomes the difficulties of using shear pins, however, the actual amount of rotation achieved at the lower end of the drill rods, where the control valve Is located, usually does not accurately agree with the number of rotations at the top end of the drill rods. Hence, it is necessary to closely monitor well fluid pressure to ascertain the mode of operation of the control valve. That is, such prior art injection control valves require operation by more highly skilled operators.

The primary reason for developing the latching reciprocating valve assembly of the present invention is to provide an alternative means of activation whereby the valve remains closed for all pressures of operation until an engagement pressure has been exceeded and subsequently the operating pressure reduced below a release pressure, the release pressure being below the engagement pressure, and where subsequent increases in operating pressure have substantially no effect upon the operating condition of the valve.

When used in the field of inflatable packers the latching reciprocating valve assembly of the present invention avoids the need for blow out plugs and shear pins that need to be replaced after each use, and provides for more stable operation and provides more controlled opening and closing characteristics with less water hammer and less stress on surrounding formations. .

SUMMARY OF THE INVENTION

Therefore, it is an object of the present invention to provide a latching reciprocating valve assembly capable of operation under differential pressure without the need to use shear pins.

In accordance with one aspect of the present Invention, there is provided a latching reciprocating valve assembly for use in controlling flow of fluid, the latching reciprocating valve assembly including: a housing having one or more ports disposed to communicate fluid through the housing; and a 8lidable seal member orientable in a closed mode of operation for sealing off the one or more ports for pressure differentials across the said housing that are below a predetermined engagement pressure differential, and the seal member being orlentable in an open mode of operation to reveal the one or more ports once the pressure differential across the housing has exceeded the engagement pressure differential and is subsequently reduced below a predetermined release pressure differential which is below the engagement pressure differential, and wherein the mode of operating of the seal member is substantially unchanged by subsequent increases in operating pressure differential. In accordance with another aspect of the present invention, there is provided a well testing tool for injecting well fluid into a well from a core barrel, the well testing tool including: an inflatable packer assembly disposable below the core barrel, whereby inflation of the inflatable packer assembly seals off an annular space in the well; a valve means situated upstream of the inflatable packer assembly for controlling the inflation and deflation of the inflatable packer; and a latching reciprocating valve assembly situated downstream of the inflatable packer assembly and in fluidic communication with the core barrel, the latching reciprocating valve assembly including: a housing having an upstream end connected downstream of the inflatable packer assembly, the housing having one or more lateral ports for injecting well fluid from the core barrel into the well; and a slidable seal member orientable in a closed mode of operation for sealing off the one or more lateral ports for pressure differentials across the said housing that are below a predetermined engagement pressure differential, and the seal member being orientable in an open mode of operation to reveal the one or more ports once the pressure differential across the housing has exceeded the engagement pressure differential and is subsequently reduced below a predetermined release pressure differential which is below the engagement pressure differential, and wherein the mode of operating of the seal member is substantially unchanged by subsequent increases in operating pressure differential; the latching reciprocating valve assembly controlling flow of well fluid from the core barrel into a region below the inflatable packer assembly to permit testing of the formation surrounding said region. In the context of the present invention the term "across the housing" in respect of differential pressures means a difference in pressure experienced by the housing from its interior to its exterior. In this case the interior is in direct communication with the core barrel and the exterior is in direct communication with the well.

Typically, the spring means is a bank of disc springs conveniently in the form of slightly domed washers, the number and resilience of which can be varied to vary the pressure differentials of the engaging and releasing pressures. These are typically referred to as a "spring stack". However, the spring means could be in the form of a coil spring.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention shall now be described with particular reference to a latching reciprocating valve assembly used in relation to a permeability testing tool used for water well completion. In this case the valve assembly is in the nature of an injection valve assembly.

This exemplary embodiment of the present invention will now be described with reference to the accompanying drawings, in which:-

Figure 1a is a longitudinal cross-sectional view of a latching reciprocating valve assembly in accordance with the present invention in the form of an injection valve assembly;

Figure 1b is a longitudinal cross-sectional view of a lower portion of a permeability testing tool for use in permeability testing of water wells, the permeability testing tool incorporating the Injection valve assembly of Figure 1a;

Figure 1c is a longitudinal cross-sectional view of an upper portion of the permeability testing tool of Figure 1b;

Figure 1d is a longitudinal cross-eectional view of an injection valve assembly according to a slightly different embodiment of the present invention, and shown rotated 180 degrees about its longitudinal central axis to reveal two of its inflation lines;

Figures 2a and 2b are respectively an end and a longitudinal cross-sectionai view of a latch stop of the Inflation valve assembly of Figure 1 a;

Figure 2c is a transverse cross-sectional view of the latch stop of the inflation valve assembly of Figure 2a, taken on line 2c-2c;

Figure 3a is a longitudinal cross-sectional view of an injection valve top sub of the inflation valve assembly of Figure 1a;

Figure 3b is a transverse cross-sectional view of the injection valve top sub of the inflation valve assembly of Figure 3a, taken on line 3b-3b;

Figure 4a is a longitudinal cross-sectional view of an injection valve lower sub of the inflation valve assembly of Figure 1a;

Figure 4b is a transverse cross-sectional view of the injection valve lower sub of the inflation valve assembly of Figure 4a, taken on line 4b-4b;

Figure 5a is a longitudinal cross-sectional view of a latch sleeve of the inflation valve assembly of Figure 1a; Figure 5b is a longitudinal cross-sectional view of a dog bone sleeve of the inflation valve assembly of Figure 1a;

Figure 6a is a longitudinal cross-sectional view of a latch piston of the inflation valve assembly of Figure 1a;

Figure 6b is an end view of the latch piston of Figure 6a;

Figure 7 is a longitudinal cross-sectional view of a spring retainer pin of the inflation valve assembly of Figure 1a;

Figure 8a is a longitudinal cross-sectional view of a spring retainer seat of the inflation valve assembly of Figure 1a;

Figure 8b is an end view of the spring retainer seat of Figure 8a;

Figure 9 is a longitudinal cross-sectional view of an end cap of the inflation valve assembly of Figure la;

Figure 10 is a longitudinal cross-sectional view of a stack of disc springs of the inflation valve assembly of Figure 1 a; and,

Figures 11a to 11c are longitudinal cross-sectional views of the inflation valve assembly of Figure 1a shown operating in an initial, running in mode of operation, an intermediate, engaged mode of operation and a final, injection mode of operation respectively.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention will hereinafter be described, by way of example only, in reference to the following particular exemplary embodiments.

Particularly as shown in Figures 1 a, 1 d and 11 a to 11 c there is shown a latching reciprocating valve assembly, in accordance with the exemplary embodiment of the present invention, conveniently in the form of an injection valve assembly 10 for use in permeability testing, of a well, or the like.

The injection valve assembly 0 includes a latch stop 20 (Figures 2a to 2c), an injection valve top sub 22 (Figure 3a and 3b), an injection valve lower sub 24 (Figures 4a and 4b), a latch sleeve 28 (Figure 5a), a dog bone 28 (Figure 5b), a piston actuator 30 (Figures 6a and 6b), a spring retainer pin 32 (Figure 7), a spring retainer seat 34 (Figures 8a and 8b), an end cap 36 (Figure 9) and a stack of disc springs 38 (Figure 10). Each of the components making up the injection valve assembly 10 is centered upon the same longitudinal axis.

The combination of the latch stop 20, the injection valve top sub 22, the injection valve lower sub 24 and the dog bone 28 is an example of the "housing" of the present invention. Also, the latch sleeve 26 is an example of the "slidable seal member" of the present invention. Further, the combination of the latch piston 30, the spring retainer pin 32 and the spring retainer seat 34 is an example of the "reciprocabfe actuator ^* of the present invention. Still further, the stack of disc springs 38 is an example of the "spring means ^* of the present invention.

In Figure lb there is shown a lower portion of a permeability testing tool 50 incorporating the injection valve assembly 10 in accordance with the exemplary embodiment of the present invention. The remainder of the permeability testing tool 50 includes an upper and typically also a lower inflatable packer assembly, both of which may be of conventional type. The upper inflatable packers assembly includes an upper inflatable packer 51 with a packer mandrel 52, an end plug 54, a packer end seal sub 55, and the lower inflatable packer assembly includes a lower Inflatable packer (not shown) with a top sub 56, an outer casing 58 and an inner casing 60. The injection valve assembly 10 threadedly connects between the outer casing 58 and the lower packer top sub 56, as described in more detail hereinafter. Each of the components making up the permeability testing tool 50 is centered upon the same longitudinal axis.

In Figure 1c there is shown an upper portion of the permeability testing tool 50. Figures 1b and 1c in combination show virtually the entire testing tool 50, except for the inflatable packers of the lower inflatable packer assembly.

As shown in Figure 1c the testing tool 50 also includes a latch head 61 for connection to a wire line, a landing shoulder 62, an O-ring seal 62a, an inflation check valve 63, a plurality of deflation ports 64, a shoulder 65, and the upper inflatable packer 51. The testing tool 50 is received in a core barrel 66 which has a landing ring 67 for supporting the landing shoulder 62, and a drill bit 68 for supporting the shoulder 65. The landing ring 67 and the drill bit 68 thereby support the testing tool 50 and prevent it from falling out of the core barrel 66 and into the well. The core barrel 66 runs in an open hole, after drilling of the hole is complete and prior to lining the hole with casing.

The mandrel 52 of the inflatable packer 51 and the packer end seal sub 55 connect to the injection valve assembly 10.

The testing tool 50 is used to determine, for example, well permeability to ascertain whether or not further drilling is required.

In the exemplary embodiment there is also a lower packer assembly 56, however this is not essential.

The injection valve assembly 10 of exemplary embodiment of t e present invention is typicaly made from metals materials and the inflatable packer assemblies are typically made from metals and elastomeric materials. The metals material components of the exemplary embodiment of the present invention are typically relatively high tensile metals materials, such as, high carbon steel and / or alloy steel. The metals materials are typically required to withstand high shear, compression and tensile stresses as well as potentially highly corrosive environments, as well as the erosive effects of well fluid. The elastomeric materials are typically rubber as commonly used in inflatable packers.

It is to be understood that some or ail of the components of the injection valve assembly 10 could be made of plastics materials or other composite materials or the like.

The injection valve assembly 10 shall now be described in more detail.

The latch stop 20, particularly as shown in Figures 1a, 1d and 2a to 2c, is generally cylindrical in shape and has an annular head 70 located at one end 71 , a cylindrical wall 72 extending therefrom and a circumferential lip 74 depending from the wall 72; the head 70, the wall 72 and the lip 74 being centered upon the same axis. The head 70 conveniently has two pin holes 78, disposed diametrically opposite said axis, for receiving a pin spanner for tightening the latch stop 20 into the injection valve top sub 22. The head 70 also has an external annular groove 80 with an O-ring seal 82 (Figure 1 a) for sealing against the inner casing 60 (Figure b). The cylindrical wall 72 has an annular groove 84 with an O-ring seal 86 for sealing against the injection valve top sub 22. The cylindrical wall 72 has an external thread 88 for threadedly engaging with the injection valve top sub 22. The lip 74 has a plurality of radially disposed ports 90. Typically, there are 8 ports 90, described in more detail hereinafter. The lip 74 also has an end 92, opposite the end 71 , disposed to bear against the latch piston 30 to retain it within the injection valve assembly 10.

The injection valve top sub 22, particularly as shown in Figures 1a, 1d, 3a and 3b, is generally cylindrical in shape and has a cylindrical base 100 with a plurality of radially disposed ports 102 (typically 8 ports 102) for allowing the flow of well fluid from the interior of the packer mandrel 52 (and hence the core barrel 86) to the well and into the surrounding formation. The base 100 has an internal depression 104 connecting the inward ends of t e ports 102 and acting as a manifold to equalise flow of well fluid between the ports 102. The injection valve top sub 22 also has a flange 106 carrying an internal thread 108, for receiving the latch stop 20, and an external thread 110, for threadedly securing the injection valve assembly 10 to the outer casing 58 (Figure 1b). The flange 06 also has an annular groove 112 receiving an O-ring seal 114 (Figure 1a) for sealing against the outer casing 58. The injection valve top sub 22 also has a collar 112 disposed from the base 00 opposite from the flange 106. The collar 112 has an internal thread 118 for receiving the injection valve lower sub 24. The base 100, the flange .106 and the collar 112 are centered upon the same axis. The collar 112 also has an outer lip 120 against which an O-ring can seal.

The injection valve lower sub 24, particularly as shown in Figures 1a, 1d, 4a and 4b, is generally cylindrical in shape and has a cylindrical base 130, a collar 132 and a flange 134, each centered upon the same axis. The base 130 has two relatively small diameter ports 140 extending radially through it (although more than 2 ports 140 could be used). The ports 140 being conveniently diametrically opposed to each other and have a narrower diameter that the ports 102. The collar 32 has an external thread 144 for threaded engagement with the internal thread 118 of the collar 112 of the top sub 22. The collar 132 also has an annular groove 146 receiving an O-ring seal 148 (Figure 1 a) for sealing the lower sub 24 to the upper sub 22 at the lip 120. The flange 134 has an outer thread 150, for engaging with the lower packer top sub 56, and an Inner thread 152 for receiving the end cap 36. The flange 134 also has an external annular groove 154 receiving an O-ring seal 156 (Figure 1a). The flange 134 also has an internal face 58 for sealing against an O-ring seal.

The slidable sleeve 26, particularly as shown in Figures 1a, 1d and 5a, (more generally referred to as the "slidable seal member" and also referred to as a "sliding port collar") is generally cylindrical in shape and has two outer annular grooves 160 and 162, one located proximate each of its end 164 and 166 respectively. The grooves 60 and 162 cany D-seals 160a and 162a respectively to seal against the base 100 of the top sub 22 adjacent the ports 102. The D-seals 160a and 162a have bases that substantially match the profile of the annular grooves 160a and 162 in which they are received so as to assist in inhibiting lift out of the seals 160a and 162a by the well fluid. Also, the D-seals have a much higher resistance to stretch than is conventionally the case with O-ring seals. Typically, the D-seals are made from high density urethane or EPDM or the like elastomeric material.

The slidable sleeve 26 also has an internally arranged annular groove 168. The groove 168 has a substantially radially disposed end wall 170 disposed towards the end 164 and capable of resisting a longitudinally directed force from the latch piston 30, as described in more detail hereinafter. The groove 68 also has a chamfered wall 172 disposed towards the end 166 and capable of allowing a longitudinally directed object to enter into the groove 168 from the end 166. Typically, the chamfer of the wall 172 is at an angle of about 20 degrees away from the longitudinal axis of the latch sleeve.26. The slidable sleeve 26 also has an external annular depression 176, particularly as shown in Figure 1a, situated between the annular grooves 160 and 162. The depression 176 marries with the depression 104 in the top sub 22 for equalising flow of well fluid between the ports 102. The end 164 has s bevelled edge 178 for engagement with the latch piston 30 as described in more detail hereinafter.

The dog bone 28, particularly as shown in Figures 1a and 5b, is generally cylindrical in shape and has two outer annular grooves 190 and 192, one locate proximate each of its ends 194 and 196. The grooves 190 and 192 each carry an O-ring 190a and 192a respectively. The O-ring 190a is disposed to seal against an inner curved surface of the base 100 of the top sub 22 and the O-ring 192a is disposed to seal against an inner curved surface of the base 130 of the lower sub 22. The dog bone 28 has a raised body 198 intermediate the two grooves 190 and 192. The body 198 has shoulders 200 and 202 that bear against the body 100 of the top sub 22 and the body 130 of the lower sub 24 so as to hold them apart. Where the size of the injection valve assembly 10 is relatively large the shoulders 200 and 202 may be increased to provide a greater contact area with the top sub 22 and the lower sub 24, whilst the remainder of the body 1 8 has a smaller diameter. That is, the dog bone 28 in smaller configurations is more likely to be substantially cylindrical, whereas in large configurations is more likely to be flared towards its ends. There is a cavity 204 defined between the outer curved surface of the bog bone 28 and the inner curved surface of the lower sub 24.

The upper sub 22, the lower sub 24 and the dog bone 28 could be fabricated in one piece, in a shape that substantially matches their outline shown in Figure 1a. The purpose for making them in separate pieces is to allow for a series of holes (conveniently referred to as inflation lines 206) to be disposed from a free end of the top sub 22 to the cavity 204 and from the cavity 204 to a free end of the lower sub 24, particularly as shown in Figure 1d. The cavity 204 forms a part of the inflation lines 206. Typically there are 8 holes forming the inflation lines 206. The series of holes are substantially parallel to a central axis of the injection valve assembly 10 and permit the flow of well fluid from above the injection valve assembly 10 to below the injection valve assembly 10, such as, for example, to permit the inflation of the lower inflatable packer located below the injection valve assembly 10.

The piston actuator 30, particularly as shown in Figures 1a, 1d, 6a and 6b (also referred to as a "reciprocable actuator ^* and a 'sliding actuator"), is generally cup shaped in longitudinal cross-section, with a body 210 from which conveniently depends 4 legs 212, each with an externally chamfered foot 14. The body has two annular grooves 2 6 disposed on its outer curved surface, each receiving an O-ring 216a arranged to seal against the inner curved surface of the dog bone 28. The body 210 and hence the piston actuator 30 is thereby able to slide within the dog bone 28. The legs 212 are substantially parallel to each other and disposed about the circumference of the body 210. The space between the legs 212 is void so as to allow the legs 212 to be able to deflect inwardly. Each foot 214 is disposed splayed outwardly at an angle complementary with the angle of chamfer of the groove 168 of the latch sleeve 26. Typically, the said angles are about 20 degrees away from the longitudinal axis of the piston actuator 30 (and the latch sleeve 26). The body 210 also has a threaded post 2 8 depending from it upon a central axis of the piston actuator 30 and in a direction opposite to that of the legs 212. T e spring retainer seat 34, particularly as shown in Figures 1a, 1d, 8a and 8b, is generally cup shaped with a hole 220 centered upon its axis and a lip 222 surrounding the hole 220. The seat 34 also has a relief channel 224 disposed along its outer curved surface parallel to its central axis and the along its open end along rim 226. The seat 34 defines a cavity 228. The seat 34 is dimensioned to be received in the end cap 36 and the relief channel 224 provides a flow path for well fluid from the cavity 228 around the seat 34 to prevent fluid lock between the seat 34 and the end cap 36.

T e spring retainer pin 32, particularly as shown in Figures 1a, Id and 7, is conveniently in the form of a bolt having a head 240, a shaft 242 and an end 244 with an internally threaded hole 246. Typically, the head 240 has a slot 248 or the like for receiving a blade of a screw driver or the like for threading the spring retainer pin 32 upon the post 218 of the piston actuator 30. The shaft 242 is dimensioned to be received in the spring retainer seat 34. The head 240 is dimensioned to be retained in cavity 228 of the spring retainer seat 34, with the shaft 242 inserted in the hole 220.

The end cap 36, particularly as ehown in Figures 1 a, 1d and 9, is generally cup shaped with an external thread 250 on its outer curved surface for engaging with the internal thread 152 of the lower sub 24. The end cap 36 has a base 252 with an external annular groove 254 receiving an O-ring seal 254a for sealing the end cap 36 to the lower sub 24. The base 252 also conveniently has two pin holes 256 disposed upon a diameter for which a pin spanner is provided to enable tightening of the end cap 36 into the lower sub 24. The end cap 36 defines a cavity 258 dimensioned to receive the spring retainer seat 34.

The stack of disc springs 38, particularly as shown in Figures 1 and 10, is an example of the spring means of the present invention. The springs 38 are made from a plurality of discs 270, each disc 270 being a frustoconical washer with a body 272 typically angled at about 7 degrees off Its plane with a convex side 274 and a concave side 276 and having a central hole 278 dimensioned to receive the shaft 242 of the spring retaining pin 32. The outer dimension of the discs 270 is sufficiently small to allow for Insertion within the dog bone 28, the lower sub 24 and the end cap 36. Typically, the springs 38 are arranged with alternate discs 270 having their concave sides 276 facing each other, although in a proportion of cases two or more of the discs 270 nest upon each other with the concave side 276. of one disc 270 receiving the convex side 274 of a neighbouring disc 270. In the exemplary embodiment, for operation at between 370 and 500 psi (suitable for an HQ size tool), there are typically 5 sets of pairs of discs 270 nested together (referred to as doubles or in a parallel arrangement) and 11 sets of single discs 270 stacked face to face (referred to as singles or in a series arrangement), being 42 discs 270 in total. All of the discs 270 have substantially the same resilience and hence spring tension. The nested discs 270 do not tend to compress but provide packing to preload the remaining discs 270, whereas the nonnested discs 270 provide resilience against compressive forces. The amount of resilient force which the disc springs 38 are compressed by can be varied by varying the number of discs 270 arranged face to face (singles), which compress, compared to the number nested upon each other (doubles), which preload the singles. The amount of resilient force that compresses the disc springs 38 can also be varied by varying the resilience of each of the discs 270. However, in the field it is more convenient to vary the resilience of the disc springs 38 by the former method.

It is to be understood that the length of the spring 38 cannot be varied, yet the resilience of the spring 38 must be variable for different pressure applications. Hence, differing arrangements of single and parallel sets of the discs 270 are tested to achieve desired pressures at which the mode of operation of the assembly 10 changes.

For example, a pressure range of 400 to 500 psi for an NQ size tool can typicaiiy be achieved by using 1 set of triple discs 270, 1 set of double discs 270 and 24 sets of single discs 270, being 53 discs 270 in total. Also, a pressure range of 350 to 450 psi for a PQ size tool can typically be achieved by using 3 sets of double discs 270 and 11 sets of single discs 270, being 34 discs in total.

One end of the stack of disc springs 38 presses against the body 2 0 of the latch piston 30 and the other end of the stack of disc springs 38 presses against the spring retainer seat 34, with the spring retainer 32 connecting the latch piston 30 to the spring retainer seat 34 and retaining the disc springs 38 thereby.

It is to be understood that one or more coil springs could be used In place of the disc springs, although disc springs are considered to be better suited to the kind of pressures that the valve 10 is expected to be subjected to.

Particularly as shown in Figure 1 d, each of the legs 212 of the latch piston 30 typicaiiy has an inwardly disposed foot for catching a resetting tool, inserted after removal of the latch stop 20, for inwardly deflecting the legs 212 and returning the latch sleeve 26 to seal off the ports 102 and thereby reset the latching reciprocating valve assembly 10. This permits the assembly 10 to be reset without needing to be completely disassembled, thereby saving time and reducing the likelihood of detritus material entering the spring stack 38.

ASSEMBLY

To assemble the injection valve assembly 10 of the exemplary embodiment of the present invention all the O-iing seals are first inserted into their corresponding grooves. Next the dog bone 28 is inserted into the lower sub 24 and the end cap 36 is tightened into the lower sub 24 upon the thread 152 using a pin spanner. The top sub 22 is then threaded onto the lower sub 24 and the latch sleeve 26 Inserted into the upper sub 22. It is important to ensure correct orientation of the latch sleeve 26 with the chamfered groove 68 closest to the dog bone 28 and the bevelled edge 178 closest to the open end of the top sub 22. The D-eeals 160a and 162a of the latch sleeve 26 are thus arranged straddling the ports 102 to close off the ports 102 and allow for a pressure differential to build up across the injection valve assembly 10 from the interior of the top sub 22 to the outer curved surface of the top sub 22 and the lower sub 24, when the tool 50 is inserted into the well.

The spring retainer pin 32 Is then inserted into the spring retainer seat 34, the disc springs 38 assembled upon the shaft 242 of the pin 32 and the latch piston 30 threaded onto the end 244 of the pin 32. This collection of components is referred to as the spring stack. The arrangement of the disc springs 38 may be adjusted to achieve differing amounts of resilience to accommodate different pressure differentials at which the injection valve assembly 10 is to actuate between its various modes of operation. A typical arrangement, for an HQ size tool 50, has 10 discs 270 arranged in 5 sets of doubles and 22 discs 270 arranged in 11 sets of singles and is used to allow for an operating pressure differential above about 1,000 kPa (about 150 psi), more particularly above about 2,500 kPa (about 350 psi).

To ensure that the cavities between the discs 270 of the disc springs 38 do not become clogged with debris it is preferred that the spring stack is packed with grease. The spring stack is then inserted into the free end of the top sub 22 and lowered in until the spring retainer seat 34 is located in the end cap 36. The feet 214 of the latch piston 30 come to rest against the bevelled edge 178 of the latch sleeve 26 and so hold it against the dog bone 28 so that the latch sleeve 26 does not inadvertently slide in the top sub 22 to reveal the ports 102.

Assembly of the injection valve assembly 10 is completed by threading the latch stop 20 into the top sub 22 with a pin spanner inserted into the pin holes 78. In this arrangement the end 92 of the lip 74 of the latch stop 20 is located proximate the feet 214 of the latch piston and thereby retains the spring stack in the top sub 22 and lower sub 24. Also, the lip 74 is spaced from the inner curved surface of the top sub 22 and forms an annular chamber 290 therewith dimensioned to be able to receive the latch sleeve 26, as described in more detail hereinafter.

The injection valve assembly 10 can then be assembled into the permeability testing tool 50 by first threading the end plug 54 onto the threaded free end of the packer mandrel 52. The end plug 54 stops the packer end seal sub 55 sliding off the packer mandrel 52. Then thread the outer casing 58 onto the lower end of the packer end seal sub 55. The Inner casing 60 is then inserted into the outer casing 58 to act as a spacer to the injection valve assembly 10 which is then threaded into the free end of the outer casing 58 with its top sub 22. The lower packer top sub 56 is then threaded onto the lower sub 24 of the injection valve assembly 10.

It is to be understood that a number of the injection valve assemblies 10 of the exemplary embodiment of the present invention could be used in the completion, testing or maintenance of a well. In such case one injection valve assembly 10 could be used in conjunction with one inflatable packer and a number of pairs of injection valve assemblies 10 and inflatable packers could be located along the length of the well, such as in a production zone, to allow for a series of staged operations to be conducted in succession. In such case the Injection valve assembly 10 uppermost or more upstream of the well is operated first and prevents communication with the lower pairs of Injection valve assemblies 10 and inflatable packers. Since the injection valve assemblies 10 do not open until pressure is reduced below the release pressure they can protect the downstream extent of the well and the other injection valve assemblies 10 and associated inflatable packers until they are required to be used.

Also, it is to be understood that pressures of operation, other than those specifically discussed herein, could be used in relation to the present invention.

USE

In use, the testing tool 50 of the exemplary embodiment of the present invention is attached to a wire line via its latch head 61 and run Into the core barrel 66 in a wen. At its final depth the landing shoulder 62 lands on the landing ring 67 and the shoulder 65 lands on the inside of the drill bit 68 to support the tool 50 at the lower end of the core barrel 66 The core barrel 66, via core rods, can then be connected to a pump and the pressure of well fluid, typically water, increased through varying pressure ranges in order to test the well.

In use, the inflation valve assembly 10 of the exemplary embodiment of the present invention works in three stages, being:

1. an Running-ln Mode (also referred to as the "closed mode of operation"), as shown in Figure 1 a, - in which the ports 102 are closed;

2. an Engaged Mode, as shown in Figure 11b, - in which the latch piston 30 engages with the latch sleeve 26 due to a pressure differential above an engagement pressure, typically above about 3,450 kPa (500 psi); and,

3. an Injection Mode (also referred to as the "open mode of operation ^* ), as shown in Figure 11c, - in which the latch ports 02 are open by a reduction in pressure differential, below a release pressure, typically below about 2,400 kPa (350 psi).

The inflation valve assembly 10 is in the Running-ln Mode (the closed mode) of operation, as shown in Figure 11 a, as the testing tool 50 is run into the well. Once the testing tool 50 is placed at its operating depth the pressure of the well fluid is increased which results in an increase in pressure differential across the inflation valve assembly 10 from its interior (high pressure) to its exterior (lower pressure).

Such increase in. pressure is associated with inflating the upper and lower inflatable packers to create a test zone for the injection test with the tool 50. Inflation fluid flows to the lower packer via the inflation lines 206 in the inflation valve assembly 10, Figure 1d.

As the pressure inside the inflation valve assembly 10 increases the latch piston 30 starts to compress the disc springs 38 and the head 220 of the spring retainer pin 32 starts to unseat from the spring retainer seat 34 and the legs 212 of the latch piston 30 slide along the inner curved surface of the latch sleeve 26 and the feet 214 move towards the chamfered groove 168 of the latch sleeve 26. To permit this movement the ports 1 0 and the channels 224 allow any fluid trapped inside the chamber 228 to be vented out to the well - thus avoiding hydraulic lock. During this mode the ports 102 remain closed and no injection of well fluid into the well is possible.

The inflation valve assembly 10 is typically operated in the closed mode of operation until the lower inflatable packer is inflated and "shut in ^* , that is closed against deflation.

In the Engaged Mode, as shown in Figure 11b, the feet 214 of the latch piston 30 enter into and engage with the chamfered groove 68 of the latch sleeve 26 and are retained therein by the shoulder 170 bearing against the free ends of the feet 214 at and above the engagement pressure. The latch piston 30 remains In the Engaged Mode until the pressure in the core barrel 66 and hence the pressure in the packer mandrel 52 is vented and reduces to below the release pressure, typically below 350 psi. Since the spring retainer pin 32 bottoms out in the end cap 36 for pressures above the engagement pressure the disc springs 36 are protected from over stressing and hence have a longer useful operating life than would otherwise be the case.

In the Injection Mode, as shown in Figure 11c, the latch piston 30 pushes the latch sleeve 26 upstream past the ports 102 to allow flow of well fluid from the interior of the injection valve assembly 10 to the exterior of the injection valve assembly 10 for injecting well fluid into the surrounding formation for testing purposes and the like. This mode requires reduction of operating pressure differentials below the release pressure. This also requires

corresponding reduction of the pressure in the core barrel 66.

The distance from the surface to the operating depth in the borehole must be taken into account in choosing the resilience of the disc springs 38 as there will be this much static head in the core barrel 66 also acting on the latch piston 30. If the static head in the core barrel 66 is too great the latch piston 30 will engage with the latch sleeve 26 but will not release, consequently the operator must swab out some rod fluid until the latch sleeve 26 does release. Alternatively, a stiffer spring stack with a higher Engaging Pressure is required.

ADVANTAGES

The latching reciprocating valve assembly 10 of the present invention has the following advantages over prior art systems:

1. Slow changes in the movement of the latch piston 30 and the latch sleeve 26 avoid sudden changes in pressure and so avoid sudden inrush of testing fluid into the formation and thus avoid damage to the formation that can occur with prior art systems that rely upon shear pins;

2. Slow changes in movement of the latch piston 30 and the latch sleeve 26 also avoids water hammer which can also damage well formations;

3. The latch piston 30 and the latch sleeve 26 can be relatively easily reset after retrieval for further use - thus having no consumable parts such as blow out plugs and shear pins common in prior art systems;

4. Especially weH suited to fragile formations because the latch piston 30 relies upon lower pressure differentials than prior art systems and has no abrupt changes in pressure as it changes modes of operation;

5. Allows for a wider range of injection pressures from, for example, about 3,450 kPa (500 psi) up to the maximum pressure capability of the valve - although lower injection pressures could be accommodated;

6. Allows for a more precise control over injection and inflation pressures; and

7. Because there are no consumable parts the assembly 10 can be tested prior to use to determine with accuracy the pressure differential at which it changes modes of operation and hence its operation in the field can be known in advance and relied upon.

The latching reciprocating valve assembly 10 of the present invention is capable of remaining in a closed condition of operation for all pressures of operation, and only moving to an open condition of operation once the pressure differential is reduced below a release pressure after having first exceeding a predetermined minimum engagement pressure.

MODIFICATIONS I VARIATIONS

It will be readily apparent to persons skilled in the relevant arts that various modifications and improvements may be made to the foregoing embodiments, in addition to those already described, without departing from the basic inventive concepts of the present invention. For example, although the latching reciprocating valve assembly of the present invention has been described with particular reference to change in operating condition from an initial closed condition to a final open condition, it could be arranged to be operated from an initial open condition to a final closed condition. Also, the externally threaded post 218 and the internally threaded hole 246 of the pin 32 could be replaced with an internally threaded hole in the piston actuator 30 and an externally threaded end for the pin 32.