Technical Field

This invention relates generally to methods and means for pumping oil and water from deep wells and more particularly to the use of reciprocating pumps powered by pressurized fluids such as gas, oil or water. Although fluid power has long been used to power such pumps, severe difficulties still exist in the pumps now available such as sand cutting, sand fouling, vapor locking, excessive use of energy, excessive downtime, excessive replacement of downhole tubing and other equipment.

Although the use of sucker rods to operate a downhole reciprocating pump is the oldest and most wide spread method, the well known high first cost and endless maintenance problems inherent in sucker rod systems have almost become accepted by many operators as inevitable which, unfortunately, drives up the cost of oil and gas and many "crooked holes" cannot be pumped at all with the use of sucker rods. The practice of "gaslifting" liquids from wells by injecting pressurized gas into a column of liquid within a tubing is well known to be an inefficient system when compressors are required to compress the gas before injection, and it cannot be used at all in most deep wells of today.

Downhole hydraulic pumps have been used since 1935, but are used in less than 1% of pumping wells today because of excessive maintenance. Typical recommendation is to change the pump every two months.

Therefore, particularly with regard to such wells as offshore wells which are generally both deep and directionally drilled, when the pressure of their produc¬ ing formation declines such that they will no longer flow on their own, a more reliable and efficient method and means for pumping is needed by the industry to gain many millions of barrels of oil and billions of cubic feet of gas, as the present invention provides.

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Background Art

US Patents 2,362,777 and 3,123,007 disclose early systems for hydraulically driving a reciprocating well pump but neither have bearing on the present invention. Many similar patents exist, some having fluid motors for attachment to conventional pumps or to operate a string of sucker rods which in turn operate a conventional downhole pump.

Coberly patent 2,952,212 operates by co-mingling spent power fluid with produced liquid from the well which requires separation and purification of the power fluid before recirculation to the downhole pump. A later Coberly patent, 3,005,414, employs a power fluid string and a separate string to return spent power fluid and a production string to convey produced liquid to the wellhead circuit.

All of the prior art known to the inventor, takes for granted: sand cutting of the pump and early replacement thereof; the pumping of all gas that gathers around the pump intake valves. Prior art must often operate with an empty or partially empty pump chamber which wastes energy and causes premature pump failure because enough liquid is not present to carry heat of friction from the pump. Said prior art has no provision to make sliding seals resistant or immune to sand cutting and, in fact, a standard design furnished today by some manufacturers, is to eliminate the seal cups and to accept a high degree of leakage around the plunger. Prior art also has no provision to preclude the pumping of sediment that enters the pump chamber which may cause excessive wear of standing valves or may fill the production tubing sufficiently to stop flow to the wellhead.

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In the volume 2a of "The Technology of Artificial Lift Methods" by Kermit Brown, page 12, the conventional method to prevent gas locking of pumps is shown wherein a "gas anchor" is shown positioned around the lower intake pipe of the pump. The idea is that gas does not travel downwardly as easily at it travels upwardly; however, even a small amount of gas that may form in the intake pipe during each stroke can accumulate and cause the pump to gas lock which is and has been a common problem to producers for a hundred years, and sand may accumulate in the "gas anchor" to stop flow altogether. All pumps in the prior art that are lowered into the production tubing have pump intake passages that may accumulate gas in such a way that the gas must pass through the pump, or worse still, that will gas lock the pump which stops pumping action. See Roeder 4,268,227, Coberly 3,005,414, Harrison 3,414,057.

Also, the various pump settings specified by "Kobe" and by "Armco", two of the leading makers of such pumps, show no settings in their latest literature wherein a pump is mounted below the pipe through which it is run.

All pump installations of the prior art known to the inventor require special members to be run in with the pipe that the pump is mounted in, such as seating nipples, pump shoes, hold down collars, screens, pump barrels and the like. The installation or replacement of such special fittings require pulling and/or running of the pipe string in which the pump is mounted which in marginal wells, may be prohibitive. Many offshore wellheads are mounted on platforms in clusters of up to 40 or more. When such wells no longer flow and require a pump, the removal of the tubing head and the installation of a stack of blowout preventers as is necessary to pull the production tubing, constitutes a very expensive and dangerous procedure as opposed to just running equipment inside of the production tubing only.

Flexible tubing is currently being lowered open-ended into wells so as to circulate fluid such as nitrogen; however, no means of remotely connecting the lower end to a downhole device has been used to the best knowledge and belief of the inventor due to the operator's inability to remotely control the dangling flimsy lower end of the flexible tubing.

Therefore, it is clear that the industry is in need of a pump and method to provide safer and more efficient ways of mounting downhole pumps within a well and in such a manner as to prevent gas locking and to minimize the effects of sand or the like that may be entrained in the well fluid.

Disclosure of Invention The present invention provides a novel oil well pump including methods and means for its installation. The pump may be affixed and reversibly sealed to the lower end of the production pipe through which it is run without the need of special fittings that have been run in as a part of the production pipe such that substantially no pocket of gas is allowed to accumulate adjacent the inlet valves, the gas being free to rise up around the pump and production pipe for removal through an annulus around the pipe instead of passing into the pump to produce hammer and/or gas lock.

The pump may- be lowered down through the production pipe on a first string of tubing until anchor members mounted with the pump are below the lower end of the production pipe string; the first string of tubing is then raised to cause the anchor members to anchor against the lower end of the production pipe and to allow a prede¬ termined tension load to be set in the first string of tubing which may then be set on slips or the like at the

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wellhead. An annular seal for sealing between the pump and the production pipe is thereby positioned within the pipe a predetermined distance above the lower end of the pipe string and the anchor members and the pump is thereby positioned within the well fluid to be pumped.

A second tubing string may then be lowered inside of the first tubing string and sealably connected with the pump remotely by a conventional j-slot connector or any other suitable connector. If flexible tubing is used for the second tubing, a joint or more of suitable rigid pipe may be run on the lower end of the flexible tubing so as to provide for alignment of the connector as well as to provide inertial force that may be required to make the connection. Pressurization of the second string of tubing from the wellhead may activate the annular seal and cause a hydraulic engine mounted with the pump to stroke the pump, thereby forcing well liquid to the wellhead through an annulus such as between the production pipe and the first tubing. The ^' annulus between the first and second string of tubing may be used to return spent fluid from the engine to the wellhead.

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For purposes of this application, fluid connection with the wellhead may denote connection to any equipment mounted at the earth's surface, such as with conventional hydraulic power supply units for powering the engine of the downhole pump or to conventional surface production equipment.

Removal of the pump from the well may be accomplished by first removing the second string of tubing and then lifting the first string of tubing with sufficient force to shear the anchor members to thus allow the pump to be raised. Said anchor members comprise an inner segment and an outer segment held together by a shear member. The anchor members are spring loaded outwardly and are formed so as to be forced inwardly when passing down through the production pipe string and to anchor against upward

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Brief Description of Drawings

Figure 1 depicts a sectional view of the pump mounting means with anchor and seal set in operating position.

Figure 2, when placed below Figure 1, depicts a sectional view of the upper part of the pump and engine.

Figure 3, when placed below Figure 2, depicts a sectional view of the lower part of the pump and engine.

Figure 4 is a fragmentary section view taken from Figure 1 depicting the seal retracted and the shear member being sheared.

Figure 5 is a fragmentary section view of a remotely and reversibly connectable fluid pressure connector assembled in operating position.

Figure 6 is an enlarged fragmentary view taken from Figure 1.

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Best Mode for Carrying Out the Invention Referring to Figure 1, the pipe string 10, through which the assembly 12 is run, terminates at a lowermost end 14. A first string of tubing 16 attached to head 26 of downhole assembly 12 comprising anchor, annular seal, engine and pump means, as by pipe threads 18, may be used to reversibly lower assembly 12 from the wellhead such that a plurality of anchor members shown generally as at 20 are below end 14 sufficiently that the rig operator is sure of that fact. Assembly 12 may then be raised slowly until upper surface 22 of anchor 20 contacts end 14 at which time the rig operator will sense a sudden increase in hook load and stop his hoist. After lifting on string 16 to develop a predetermined load sufficient to offset thermal relaxation of string 16 but less than a predetermined load required to shear anchor 20., the operator may then suspend string 16 on conventional slips and seal around the upper portion of string 16 in a conventional manner at the wellhead. Anchor 20 may be positioned in rectangular slot 24 within head 26 such that anchor 20 may be retracted into slot 24 such that end surface 28 does not protrude from head 26; however, spring 30 serves to hold anchor 20 at the extreme outward position as limited by lateral wing 32 of anchor 20 contacting inner diameter 34 of head 26. It may now be understood that as assembly 12 is lowered within string 10, anchor members 20 are depressed by inner surface 36 of string 10 until anchor 20 reaches a pipe collar at which time anchors 20 are moved outwardly by spring 30 and then are again depressed as angular guide surface 38 of the outer lower portion of anchor 20, contacts the upper end of the next lower joint of pipe. Therefore, when anchors are lowered below surface 14, they will be in the extreme outward position so as to positively contact surface 14 when raised to that elevation. Each anchor 20 comprises an inner segment 40, an outer segment 42 and a shear member 44 which normally holds segments 40 and 42 together which

contact on a common interface 46 formed on a suitable angle to allow a shearing action to occur between the segments when a predetermined vertical load is applied downwardly on surface 22. Shear member 44 is of such dimensions and of suitable material so as to shear when a desired load is applied downwardly on surface 22 of segment 42. It is now clear that anchor members 20 may be selectively released by lifting string 16 with sufficient force to shear members 44. Of course, the shear force must be selected great enough so that shear will not occur when the slips are set during installation.

The lower end of a second tubing string 46 may be connected to collar 48 as by means of pipe threads 47 or by a remote connector as later described. String 46 must be of sufficient diameter as to be run inside of string 16. At its lower end, collar 48 may be connected with generally cylindrical stem 50 as by threads 52 and seal 54 may be formed within collar 48 and around the upper portion of stem 50. Conduit 56 may be formed within stem 50 so as to receive power fluid through tubing 46 from the wellhead. Conduit 58 may be formed within stem 50 so as to convey spent power fluid to annulus 60 between strings 16 and 46 and thence to the wellhead. Conduit 62 may be formed within stem 50 so as to convey produced well fluid to annulus 64 between strings 10 and 16 and then to the wellhead.

Annular seal member 65 may be of a suitable elastomer and positioned within cooperating groove 66, formed around the periphery of head 26 a suitable distance above anchor members 20, seal 65 being of sufficient elasticity and strength as required to: be moved by hydraulic pressure into sealing position against surface 36; seal against fluid pressure within annulus 64; return elastically to within groove 66 after release of pressure. Seal 65 may be moved into said sealing position per Figure 1 by means of fluid entering space 68 formed between seal 65 and groove 66 so as to provide a pressure to and through seal 65

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against surface 36, of greater magnitude than the fluid pressure within annulus 64.

So as to selectively activate or deactivate seal 65, differential annular piston 70 is provided for opening and closing communication between space 68 and conduit 56 while simultaneously closing and opening respectively, communica¬ tion between space 68 and portion 67 of annulus 64 below seal 65. Thus, when power fluid within conduit 56 is raised to a predetermined value, piston 70 is forced to its lowermost position as shown in Figure 1 so as to allow power fluid to flow through annular space 72 within which the small diameter portion of piston 70 is positioned, and thence into space 68 through passage 74. When piston 70 is in the position of Figure 1 , outer cylindrical surface 76 of piston 70 which is in sliding sealing contact with inner cylindrical surface 71 of head 26 stops fluid flow from passage 78 connected with space 68. When power fluid pressure within conduit 56 is lowered below said predetermined pressure, piston 70 is forced to the extreme upper position as shown in Figure 4 by fluid pressure from conduit 58 through lateral passage 59, which allows high pressure fluid that may be within space 68 to be relieved through passage 78, around a reduced diameter portion 88 of piston 70 and within a lower and enlarged portion 73 of annular space 72 and thence through passage 80 to portion 67 of annulus 64 below seal 65. The pressure area below piston 70 may be formed so as to be a desired amount greater than the pressure area above piston 70 such that piston 70 will be urged to the upper position by equal pressures and unless the fluid pressure above the piston exceeds the pressure below the piston by a predetermined percentage. The resilience of seal 65 then may serve to return seal 65 to retracted position per Figure 4. The inner diameter of piston 70 may be dimensioned for a slid- ing fit with an outer diameter of stem 50 as at 82; the upper outer surface 76 of piston 70 may be dimensioned for a sealing sliding fit with a first inner cylindrical

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surface 71 of head 26; the lower outer surface 84 of piston 70 of larger diameter than 71 may be dimensioned for a sliding fit with a second inner cylindrical surface of head 26 as at 86; an outer surface 88 of piston 70 of smaller diameter than surface 76 and positioned between the upper and lower cylindrical surfaces serves to allow fluid flow within cylindrical surfaces 71 and 86. When piston 70 is in the upper position ^* per Figure 4, flow from conduit 56 to space 68 is prevented but flow from space 68 around diameter 88 and thence through- space 73 and passage 80 to annulus 64 below seal 65 is allowed. So as to seal the larger end of piston 70, conventional sliding seals as at 90 and 92 may be provided to seal against cylindrical surfaces 86 and 82 respectively. Various conventional static seals typically shown at 54 may be provided as required to seal the system.

Stem 50 extends axially through and downwardly from head 26 to extend through a hydraulically powered pump generally shown at 100 in Figures 2 and 3, terminating at end 102. Threaded nut 104, when tightened on threads 105 formed on the lower diameter of stem 50, acts against annular member 106 mounted and sealed around stem 50, maintains stem 50 in tension over and above any anticipated working load to thereby substantially reduce the tendency of stem 50 to buckle or to suffer fatigue in service.

Tubular jacket 108 mounted concentrically around a lower portion of stem 50 is connected with the lower portion of head 26 and member 106 as by threads or the like as at 107 so as to form annulus 110 between the stem and jacket, annulus 110 terminating at the lower end of head 26 and the upper end of member 106. Annular shaped valve 112 positioned in sliding sealing contact around stem 50, also is provided with sliding sealing means 114 to cooperate with inner cylindrical surface 116 of jacket 108, such that valve 112 may freely move between an upper position limited by the lower end of head 26 and a lower position limited by shoulder 118 mounted with stem 50. When valve 112 is in

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the position depicted in Figure 2: well fluid may flow into the upper end of annulus 110 through intake ports as at 120 formed through wall of jacket 108, through passages 122 formed longitudinally through valve 112 and thence into upper pump chamber 124 which is a segment of annulus 110 below valve 112 and above slide valve 126, later defined; well fluid may not flow between chamber 124 and passage 128 connected with conduit 62 which in turn is connectd with annulus 64, flow being prevented by the sliding sealing contact between valve 112 and stem 50. When valve 112 is in a position similar to that of valve 212 of Figure 3: sealing surface 130 of valve 112 seals against sealing surface 132 on the lower end of head 26 so as to prevent flow of well fluid between chamber 124 and ports 120; passage 128 then being open to chamber 124 so as to allow flow between chamber 124 and annulus 64 through conduit 62.

Valve 212 performs with respect to lower pump chamber 224 as does valve 112 with respect to upper pump chamber 124, similar features being numbered higher by 100.

Enlarged cylindrical portion 134 of stem 50 positioned centrally with respect to surfaces 132 and 232 comprises stop shoulders 136 and 138 respectively so as to limit the axial movement of annular slide valve 126 which is mounted around portion 134 with a sliding sealing fit therebetween. The outer perifery of slide valve 126 also engages the inner diameter 140 of annular plunger 142 with a sliding sealing fit against power fluid.

Annular plunger 142 is sealingly connected at an upper end with cap 144 and at a lower end with cap 146, each cap having sliding seals as at 148 for sliding sealing engagement with outer cylindrical surfaces 150 and 152 of stem 50, said surfaces being of smaller diameter than portion 134. Annular spaces of variable volume 154 and 156 are thereby created within plunger 142, above and below slide valve 126 respectively. It is now clear that plunger 142 may reciprocate along the stem axis between valves 112

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and 212 and within jacket 108. So as to prevent flow between upper pump chamber 124 and lower pump chamber 224, annular sliding seals as at 158 may be mounted within jacket 108 to seal against the outer cylindrical surface 160 of plunger 142.

When slide valve 126 is in a lowermost position as shown in Figure 2: communication between conduit 58 and annular space 156 is open through lateral passage 162 formed within stem 50 and through passage 164 formed within slide valve 126 to thereby allow spent power fluid to return from annular space 156 to annulus 60 and thence to the wellhead; communication between conduit 58 and annular space 154 is closed as wall 166 of slide valve 126 blocks lateral passage 168 connected with conduit 58; communication between conduit 56 and annular space 154 is open through lateral passage 170; communication between annular space 156 and conduit 56 is closed as wall 172 of slide valve 126 blocks lateral passage 174 connected with conduit 56. When slide valve 126 is in an uppermost position, the upper end 176 abutting shoulder 138: passages 170 and 162 are closed; passage 168 is aligned open with passage 178 formed within valve 126; passage 174 is open because valve 126 is above passage 174; communication exists between space 154 and annulus 60; communication exists between space 156 and tubing 46.

Immediately before plunger 142 reaches a lowermost position as depicted in Figures 1 and 2, lower end 180 of cap 144 is dimensioned to contact upper end 176 of slide valve 126 so as to move valve 126 downwardly: to close passage 174; to begin opening of passage 170; to close passage 168; to begin opening of passage 162. As passage 170 begins to open, high pressure power fluid from passage 170 acts on end 176 of slide valve 126 to move it immediately to the lowermost position per Figure 2. Thus, high pressure power fluid from conduit 56 may enter space 154 to act upwardly on cap 144 while spent fluid of lower

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pressure is forced from space 156 into conduit 58 as cap 146 moves upwardly to reduce the volume of space 156. Immediately before the plunger reaches an uppermost position, the upper end 145 of cap 146 moves slide valve 126 upwardly to again reverse the stroke in a similar manner.

Although shoulder 182 formed on the stem connecting cylindrical surfaces 150 and 134 is shown contacting a cooperating shoulder of cap 144 in Figure 2, such contact occurs only when the pump is at rest, the plunger reversal occurring before such contact can occur when the pump is in operation. Thus, a smoothly operating hydraulic engine is provided for the pump.

Operation of the engine and pump may now be understood. As a suitable power fluid is forced from the wellhead by any suitable means through tubing 46, conduit 56, passage 170 and into space 154 to act upwardly upon cap 144, plunger 142 is caused to move upwardly such that cap 146 acts upwardly on spent power fluid within space 156 to force it through passage 164, passage 162, conduit 58 and annulus 60 to the wellhead for recirculation through a selected means of pressurization. The plunger is thereby caused to reciprocate, reversed as explained above, as long as power fluid of sufficient volume and pressure is supplied to tubing 46. As the plunger begins an upward stroke, a pressure drop is caused within lower pump chamber 224 which together with well pressure acting against the lower end of valve 212, moves valve 212 axially upward to contact shoulder 218, thereby closing passage 228 and allowing well fluid to flow in through ports 220 and passages 222 to fill lower pump chamber 224 as it gains maximum volume. As the plunger begins to move upwardly: outflow of well fluid from upper pump chamber 124 causes valve 112 to move axially upward until, surface 130 contacts surface 132 to thereby prevent further flow of well fluid through ports 120; the lower end of valve 112 clears passage 128 such that pressurized well fluid- is forced into

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(15) conduit 62 to annulus 64 and to the wellhead as produced well fluid, upon reversal of the plunger movement, well fluid is received into the upper chamber through ports 120 and well fluid is produced from the lower chamber in a similar manner.

So as to protect the pump and engine against sand cutting as suffered by conventional pumps, surfaces of moving seals that are exposed to well fluid may be coated with material harder than the sand, as taught by my co-pending US Patent Application SN 06/421,503. Such a coating process is now availabe commercially. Surfaces of the present invention to be so coated may include surfaces 130, 132, 150, 152, 116, the outer perifery of seal 114,. the inner surface of seal 148, the inner surface of seal 158 and other similar surfaces.

Valves 112 and 212 are positioned below the lower end 14 of pipe string 10 such that gas cannot accumulate near the valves but will rise around the pump and string 10, through the well liquid toward the surface. Intake ports 120 and 220 are spaced around the jacket so as to reduce velocity of incoming well fluid as compared with a conventional single intake port, to thereby reduce or eliminate intake of sand that may be entrained in the well fluid. However, should some sand enter ports 120, the reduced velocity resulting upon entering the greater flow area within the jacket will tend to cause the sand to fall out on top of valve 112, the sand then being removed through ports 120 during the next rise of valve 112 aided by the temporary outflow and by lift of the upper seal ring 111 to the level of ports 120. Any few minute particles that may enter chamber 124 can easily be washed out with the produced well fluid. A similar cleansing action occurs through ports 220 as particles settle out on valve 212 and on member 106 so as to be washed out with the next temporary outflow from chamber 224.

Figure 5 depicts a remotely connectable fluid pressure connecter 302 for effecting a pressure tight connection

between the lower end of a string of flexible tubing with downhole assembly 12. Although such a connector is required to remotely connect flexible coil type oilwell tubing, it may be used to remotely connect conventional rigid oilfield tubing if desired. Upper portion 300 may be attached to the lower end of one or more joints of rigid pipe by threads or the like, as required to axially align portion 300 with lower portion 326 and to provide inertia as may be required to join said upper and lower portions, without which the connection could not be made. Portion 300 is formed with outer diameter 304 of sufficient dimension to pass within inner surface 36 and to guide lower cylindrical end 306 of portion 300 to enter internal conical guide surface 308 of portion 326 adjacent the upper end of portion 326 such that end 306 will be positively and easily guided to enter suitably dimensioned bore 310 of portion 326 to the extent that the contact of stop means such as opposing shoulders at 312 stop downward movement of portion 300 to thereby align a plurality of anchor members as at 314 mounted with portion 300 with internal annular groove 316 formed within concentric bore 310. Groove 316 and anchor members 314 are formed with cooperating conical surfaces as at 318 such that an upward force on portion 300 will tend to cause anchors 314 to slide inwardly within mounting slots 320 formed in a side wall of portion 300. Tubular seal member 322 of a suitable elastomer may be retained and sealed as at 323 the upper end thereof with portion 300, through bore 301 so as to extend downwardly to abut the innermost surfaces of anchors 314 as at 324 and to project downwardly below the lower end of portion 300 sufficiently to effect a seal with portion 325 as at 327. Bore 328 of portion 326 is dimensioned so as to receive and seal with member 322 when portion 300 is lowered into portion 326 so as to contact surfaces 312. Anchors 314 are dimensioned so as to be retracted into portion 300 sufficiently to pass through bore 310, an upward retracting force being generated by conical surface-

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308 upon downward movement of anchors 314 into portion 326 and by conical surfaces 318 upon upward movement of portion 300 from its lowermost position against shoulder 312. So as to prevent outward movement of anchors 314 beyond a desired limit, suitable stop means may be provided such as wings 329 formed to have innermost cylindrical surface 330 of anchor 314 to abut the outer cylindrical surface of tubular seal member 322. Wing 329 may be formed with an outer cylindrical surface so as to abut a cylindrical recess formed within bore 301 such that' when anchors 314 are positioned at their outermost limit, member 322 is substantially of constant diameter. Therefore, it may be understood that when anchors 314 are depressed inwardly as by surface 308, elastic member 322 is deformed inwardly to thereby provide a returning force to return anchors 314 to their outermost position when the inward depressing force is removed.

The conical angle of surfaces 318 are formed and the inner surfaces 330 of wings 329 are dimensioned such that a given fluid pressure within the connector when in sealing position per Figure 5, exerts sufficient force on wings 329 to be transmitted to surfaces 318 so as to provide a holding force against upward movement of portion 300 that is greater than a force tending to cause upward movement of portion 300 as caused by said given fluid pressure acting against the included area defined by bore 328. It may now be understood that internal fluid pressure within the rating of the connector will not cause the connector to lose sealing engagement. It may also be understood that the connector may be remotely sealingly connected by lowering portion 300 connected with the rigid pipe and the flexible tubing as above described into a previously mounted portion 326, with sufficient velocity to engage the portions. It may now be further understood that the connector may be remotely disconnected when fluid pressure within the connector is less than a predetermined value, by lifting on the flexible tubing which may then be removed

^{0 86} /° ²⁹⁷¹ ₍ , _{g )} PCT/US84/018 6 from the well. The weight of the rigid pipe connected with portion 300 serves to maintain engagement of the connector during service, the internal fluid pressure therein having no net parting force thereof. A variation of this embodiment may be as follows: should it be desired to practice the present invention by mounting assembly 12 at some elevation above the lower end 14, openings may be formed through the wall of pipe string 10 by conventional perforating tools, the holes being at an elevation between the elevations that the intake valves and annular seal 65 will be set. Assembly 12 may then be lowered into string 10 as before described, such that anchors 20 are immediately below a selected collar joint of string 10. Assembly 12 may then be raised such that anchors 20 anchor against the lower end of the joint of pipe uppermost of that collar joint, as before described for surface 14. It is now clear that well fluid may rise up within string 10, liquid being pumped upwardly within string 10, gas being free to rise up within string 10 around the pump, past the intake valves, through the openings through the wall of string 10 and upwardly through the annulus around string 10 to the wellhead.

Upon study of these specifications and drawings, other modes and embodiments within the spirit and scope of the present invention will be obvious to those skilled in the art.

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