Well Bore Circulating Tool Including Positioning Method By Casing Annulus Fluid Stretching Tubing String

Abstract

The tool disclosed equalizes fluid pressure around an upper pair of oppositely facing, cup-type packers on an upper mandrel carried sleeve associated with a drag element assembly, and bypasses fluid pressure through a lower mandrel channel around a lower pair of oppositely facing, cup-type packers carried on a lower mandrel, the mandrels being rigidly connected, and the lower mandrel carrying a sleeve providing a circulating port and carrying a drag assembly. The mandrel may be rotated 180.degree. with relation to sleeves to close equalizing ports and circulating ports, and then circulating fluid can be pumped down casing annulus to set second packer to stretch tubing string to place squeeze port in lower mandrel straddle casing perforations and to set squeeze packers.

Description

The invention relates to well tools, and has as an important object the provision of a well tool adapted to stretch the tubing string from a position above and proximate an upper perforation to a position with lower or squeeze packers straddle such upper perforation.

It is also a further and important object of this invention to provide a tool of this class which has a lower mandrel adapted to be used separately, with two packers reversed, to serve in the recovery of service fluid up the squeeze bore and tubing string.

It is also an important object of the invention to provide a tool of this class and method of use, when not under stretch that extends distance between squeeze packers to service a substantial vertical distance of perforations, with the tool providing an uppermost downwardly opening, cup type packer to delimit service fluid space as to such fluid which returns through upper serviced perforations into the well bore.

It is yet an additional and salient object of the invention to provide a well tool and service method, whereby the tool may be converted from a fluid equalized, well entering position, to a closed port position, simply by rotating mandrel (or tubing string) 180.degree. with relation to port sleeves, as held by drag assembly contact.

It is also a definite and most important object of the invention to provide a tool adapted to have parallel packer bypass and service fluid delivery channels through the mandrel.

It is still another and further object of the invention to provide a tool of this class which is readily adapted to various usages by the simple expedient of changing parts.

Other and further objects will be apparent when the specification is considered in connection with the drawings, in which:

FIG. 1 is an elevational view of a tool comprising an embodiment of the invention in position in an oil well casing shown in section; the two upper sleeve equalizing ports (in dotted lines) being in communication through the mandrel exterior, the circulating port (in lower sleeve), and the squeeze port (between lower pair of packers) being open;

FIG. 2 is an elevational view of the tool shown in FIG. 1 after the tubing string has been stretched by the weight of circulating fluid pumped down casing annulus to set the lower cup type packer of the upper pair thereof, thus disposing the lower pair of cup type packers straddle an uppermost perforation with "squeeze" port open for pressurized service fluid down mandrel to wash the perforation; the two equalizing ports and the circulating port being shown open; also an open bypass port (through lower end of mandrel) is shown in this position;

FIG. 3 is a sectional elevational view of the tool shown in FIG. 1 after the tubing string has been lowered to dispose the lower pair of cup type packers to straddle a lower perforation; the tool being in condition for service as in FIG. 2;

FIGS. 4A, 4B, 7A and 7B, are hereinbelow described, considering the tool to have been rotated 90.degree. to right from the position shown in FIG. 1, as follows:

FIG. 4A is a sectional elevational view of the upper parts of the upper portion of tool shown in FIGS. 1-3, inclusive;

FIG. 4B is an elevational view of the lower parts of the upper portion of the tool shown in FIGS. 1-3, inclusive;

FIG. 5 is a transverse sectional plan view, taken along line 5--5 of FIG. 4A and along line 5--5 of FIG. 4B;

FIG. 6 is a transverse sectional plan view taken along line 6--6 of FIG. 4A;

FIG. 7A is a sectional elevational view of the upper parts of the lower portion of the tool shown in FIGS. 1-3, inclusive;

FIG. 7B is a sectional elevational view of the lower parts of the lower portion of the tool shown in FIGS. 1-3, inclusive;

FIG. 8 is a transverse sectional plan view taken along line 8--8 of FIG. 7A;

FIG. 9 is a transverse sectional plan view taken along line 9--9 of FIG. 7B;

FIG. 10 is a transverse sectional plan view taken along line 10--10 of FIG. 7B;

FIG. 10A is a transverse sectional plan view taken along line 10A--10A of FIG. 7A;

FIG. 11 is an alternate usage view, showing the parts shown in FIG. 7B, (lower parts of lower portion), but with the lower cup-type packer of the lower pair of packers removed;

FIG. 12 is a lower continuation of the alternate usage shown in FIG. 11, with the lower cup-type packer of the lower pair of packers shown installed on a lower extension mandrel;

FIG. 13 is a transverse sectional plan view taken along line 13--13 of FIG. 11, indicating in dotted lines the removal of the lower cup type packer of the lower pair of packers;

FIG. 14 is a transverse sectional plan view taken along line 14--14 of FIG. 12, showing the lower cup packer of the lower pair of packers as installed on the lower extension mandrel; and

FIG. 15 is a small scale sectional elevational view of the construction of the lower portion of the tool as employed alone for an alternate usage.

Referring now in detail to the drawings, in which like reference numerals are assigned to like elements in the various views, a well tubing string 10 is shown in FIG. 1 in a well casing 11 in position in a cased well bore 12 which has been cemented in the bore by cement 13 with a fluid negotiable space 14 being indicated just outwardly of the casing as that requiring service with the general formation of the earth further outwardly being indicated by the reference numeral 15. Below the tubing string 10 the tool 16 is connected upwardly to the tubing string lower end by a clutch sub or connection member 17, forming part of an upper mandrel 25. An upper sleeve 18 is shown immediately below the clutch sub 17, the upper sleeve 18 and clutch 17 being relatively rotatable, as indicated by the clutch jaw 21 forming part of the clutch sub 17, and to be further described hereinbelow in relation to a stop jaw on the upper sleeve 18, not shown in FIGS. 1-3, inclusive.

An upper equalizing port 31 is shown to be on the reverse side of the upper sleeve 18 in FIG. 1, and therebelow on such sleeve a pair of cup-type, oppositely facing packers are mounted, with upper packer 19 opening downwardly, and lower packer 20 opening upwardly. Then, in the upper sleeve 18, below the lower packer 20, a lower equalizing port 32 is provided to communicate with the upper port 31 by means of a longitudinally extending slot in the mandrel outer surface, to be hereinbelow described. Also a key 23 is indicated on the reverse side in FIG. 1 for the purpose of connecting the upper sleeve 18 against rotating with the mandrel, as the friction pad or drag assembly 24, on the upper sleeve 18 bears frictionally against the inner wall of the casing 11.

Below the friction pad assembly 24 there appears a larger diameter upper mandrel member or sub 26, and there is indication in FIG. 1 that the lower surface of the friction unit 24 and the upper surface of this sub 26 move relatively slidably over each other as when the mandrel may be rotated.

A tubing or tubular member 27, which may be of substantial length, is shown connecting the lower member or sub 26 of the upper mandrel section 25 with a sub 28, comprising an upper member of the lower mandrel 30. The aforesaid tubing member 27 may be considered optionally as part of either the upper mandrel section 25; also as part of the lower mandrel section 30, as indicated in FIGS. 1-3, and in FIG. 4B.

The lower mandrel sub 28 is clutch connected by means of clutch jaw 43, engageable with a stop member (not shown in FIGS. 1-3) which upstands from the head or upper member 29 of a lower sleeve 35, whereby it may be known whether or not a circulating port 33, shown in full lines in FIG. 1, communicates with a matching lower mandrel port (open position) or occludes such matching port, (closed position). A friction assembly or drag unit 34 is also carried by the lower sleeve 35 to bear against the casing inner wall to prevent the lower sleeve 35 from turning when the tubing string with mandrel, carrying lower sleeve 35 thereon, is rotated, as to change port positions from those shown in FIG. 1 to those shown in FIGS. 2 and 3.

Below the friction pad assembly, or friction or drag unit 34, an enlarged diameter, lower mandrel section sub or member 36 is shown in FIG. 1, with the lower surface of the friction unit 34 being shown to indicate that this surface and the upper surface of the lower mandrel sub or member 36 move relatively slidably over each other responsive to mandrel rotation.

Below the lower mandrel sub 36, the lower mandrel continues as a reduced diameter member 37 with a bypass port 38, indicated on the reverse side in FIG. 1, being provided to bypass circulating fluid a round a pair of cup-type, oppositely facing packers 39, 40, upper packers opening downwardly and lower packer opening upwardly. The bypass route, not indicated, is preferably through a separate bore in the mandrel lower end to the port 38. Below the lower packer 39, the lower mandrel section 30 continues as a sub 41 and terminates in an open or hollow bull plug 42.

A port termed the squeeze port 45 is provided in the lower mandrel member 37 below the bypass port 38 and between the packers 39, 40, the functioning of this squeeze port 45 being the most important and salient usage of the tool 16. In FIG. 1, the tool is shown as lowered into the well bore 12 with the ports 31, 32, open to bypass well bore fluid around packers 19, 20; also the circulating port 33 between well bore and mandrel interior is open in this position.

Additionally, the continuously open bypass port 38 permits well bore fluid passage around the packers 39, 40 through a passage in the mandrel separate from the hollow service fluid path therethrough, while the continuously open squeeze port 45 is open so that the lowered tool may provide fluid passage through this port. In this condition the packers 19, 20 and 39, 40, formed and installed in unset position, remain unset because of the aforesaid open condition of all of the ports.

The tool 16 has been lowered in FIG. 1, as determined by measurement of payout against known pipe tally, to a position or elevation calculated to be just above known uppermost perforations 46 in a perforated casing area. Then, as shown in FIG. 2, the tubing string 10 has been rotated to the right, as viewed looking down from the top of the well 12, whereby the upper mandrel 25 is rotated 180.degree. with relation to the upper sleeve 18, as it is held against rotation by the upper drag assembly 24; also the lower mandrel 30, rigidly connected to the upper mandrel 25, is rotated 180.degree. with relation to the lower sleeve 35, as it is held against rotation by the lower drag assembly 34.

Thus, in FIG. 2 the respective upper and lower mandrel clutch jaws 21 and 43 are shown to have been moved 180.degree. counterclockwise or to the right, as viewed looking down from the top of the well. In like manner the equalizing ports 31, 32 are now shown in full line position, the circulating port 33 and the squeeze port 45 are shown in dotted position, while the bypass port 38 is shown in full line position.

After the tubing string 10 has been rotated, as aforesaid, to close the equalizing ports 31, 32 and circulating port 33, conventional circulating fluid is pumped down the casing annulus to set the upwardly facing or opening packer 20, and pressure is kept up on the circulating fluid with the consequence that the tubing string is stretched to move the tool 16, including the lower pair of packers 39, 40 downwardly. Also, service fluid is pumped down the tubing string 10 and the bore or hollow passage through the mandrel sections 25, 30, to pass out the squeeze port 45 and set the lower packers 39, 40.

Then, when the lower packer 40 has been moved far enough downwardly to uncover an upper perforation 46, a drop in the service fluid gauge at the top of the well will indicate that upper perforation 46 is being served by the service fluid washing through the perforations into the loose or relatively open service space 14. The pressure upon the service fluid down the tubing string 10 may then be increased as dictated by the "squeeze" service which may be required to completely wash through the perforations and otherwise service the well bore 12.

As shown in FIG. 3 the tubing string 10 and tool 16 thereon, have been lowered from the top of the well bore to dispose the tool in the next lowest perforation level to service the perforations 47. As it is known from the perforation record what distance there was between perforations, it is a simple matter to effectuate these short changes, which ordinarily require simply lowering the tubing string -0 the short known distance between perforations. Also, indication is given by the lower packer 40 being lowered to uncover a next lower perforation 47, as there will be a pressure drop indicated in the service pressure fluid gauge at the top of the well bore, as the "squeeze" pressure is relieved by fluid passing out the perforations 47 not selected for service.

An alternative construction is indicated in dotted lines in FIG. 2, which shows a clutch stop 48 extended downwardly as part of the upper sleeve 18, and a clutch jaw 49 on upper mandrel 25 having been rotated to the right or into counterclockwise stop contact with the aforesaid clutch stop 48. Such a clutch arrangement may be employed in place of the upper mandrel clutch jaw 21, and its stop, not shown, FIGS. 1-3. Also the clutch arrangement 48, 49 may be employed as an additional arrangement.

The construction of the tool 16 shown in FIGS. 1-3, inclusive, may be set forth in detail hereinbelow, as the tool 16 is disclosed in FIGS. 4A through FIG. 10A, inclusive. In FIG. 4A the lower end of the tubing string 10 is shown connected to a sub 17 which has been modified by relieving the lower end part to provide the clutch jaw 21, which is rotated to the left, (clockwise), to stop position (FIG. 6) against a stop jaw or lug 22, thus to place the tool 16 in best condition to be lowered into the well bore with the equalizing ports 31, 32 open, as shown in FIG. 1. A roller bearing assembly or antifriction unit 50 is shown in FIG. 4A interposed between the clutch sub 17 and clutch head 51 of the upper sleeve 18, thereby to facilitate relative rotation therebetween.

The tubing string 10 is shown in FIG. 4A as having a conventional concentric bore 52 therethrough while the clutch sub 17 has concentricly therein a bore 53 and an enlarged diameter counterbore 54. The upper mandrel clutch sub 17 has threaded thereinto the upper mandrel central tubular member 57 having an eccentricly disposed main bore 56 therein which communicates upwardly with the clutch sub counterbore 54. A longitudinally extending slot 58 has to be provided in the upper mandrel central member 57 to establish fluid communication between the upper equalizing port 31 and the lower equalizing port 32 (FIG. 4B) in the upper sleeve 18 below the clutch head 51. Thus the well bore fluid has an equalizing passage around the upper, downwardly facing, cup-type packer 19 thereon, and also around the lower, upwardly facing, cup-type packer 20. The respective packers 19, 20 are fixedly positioned on the upper sleeve portion 59, below the sleeve clutch head 51 by respective pairs of lock nuts 60a, 60b threaded respectively downwardly and upwardly on the sleeve portion 59, with the nuts 60a to bear against the respective packers 19, 20, as the packers are stopped by respective shoulders 61a, 61b provided on the sleeve portion 59.

The upper sleeve 18 terminates, below the lower equalizing port 32, in the key 23 which engages in a conventional key slot provided therefor in the uppermost part of the head 62 of the friction element mounting sleeve or body 63 of the upper drag assembly or friction unit 24. Such sleeve or body 63 is received upon the lower portion of the upper mandrel central member 57, which is shown in FIG. 4B as having been drilled concentricly from its lower end to provide a lower, enlarged concentric bore 64. Obviously, the expedient of drilling the central member 57 eccentricly from the top for a necessary distance permits stock in which the longitudinally extending groove or slot 58 may be formed as an equalizing or bypass channel between ports 31, 32 above and below the upper set of packers 19, 20.

The upper drag assembly 24, as shown in FIGS. 1, 2 and 3, is shown in FIG. 4B (and in plan view in FIG. 8) as comprising a plurality of friction elements or drag members 65 disposed in equally, angularly spaced apart slots 66 in the body 63 to be urged outwardly by leaf springs 67 within respective slots 66 and thus under each drag member 65. A retainer ring or band 68a holds the upper foot 69a of each drag member 65 to limited outward movement and a corresponding band 68b restrains the lower foot 69b of each drag member 65.

The lower end portion 70 of the upper drag assembly 24 is counterbored upwardly to receive therein the reduced diameter head of the upper mandrel lower sub 26 of the upper mandrel 25, such mandrel sub 26 being internally threaded from its upper end to be threaded full up on the lower end portion of the upper mandrel central member 57 to restrain a roller bearing antifriction unit 50 between the lower portion 70 of the drag assembly body 63 and the top surface of the aforesaid upper mandrel lower sub 26.

The lower sub 26 of the upper mandrel 25 is connected to the upper sub 28 of the lower mandrel 30 by means of the tubing or tubular member 27. Considering FIG. 7A in connection with FIG. 10A, a portion of the lower end part of the lower mandrel upper sub 28 is cut away over approximately 240.degree., leaving a downwardly extending clutch jaw 43 (FIG. 10A) of approximately 120.degree.. The condition is as indicated in FIG. 1 in that the lowe mandrel 30 has been rotated to the left (clockwise) to abut the upstanding clutch stop or lug 44 comprising part of the head 29 of the sleeve or body 71 on which is mounted the lower drag assembly 34 (FIGS. 1, 2, 3).

The lower mandrel 30 includes a central tubular member 72 on which the body or sleeve 71 of the lower drag assembly 34 is mounted, the lower drag assembly 34 being identical in parts and reference numeral assignment with the upper drag assembly 24 shown in FIG. 4B. Also the drag assembly body 71 includes a lower member 73 having its upper part constructed identically with the construction of the lower end portion 70 of the upper drag body 63. The lower mandrel central tubular member 72 passes through the aforesaid lower member 73 of the drag assembly body 71, and a lower mandrel sub 36 has its upper end portion threadably engaged upon the end portion of the central tubular member 72, whereby to complete assembly of the lower mandrel 30 with the drag assembly 34 in position thereon whereby the drag assembly lower member 73 may remain stationary as the mandrel 30 is rotated with relation thereto.

The drag assembly body 71 of the drag assembly 34 provides a circulating port 33 therein, which is in communication with a circulating port 75 in the lower mandrel tubular member 72, whereby as the tool 16 is lowered into a well bore defined in tubular member bore 74 and in the casing annulus are in communication.

The lower mandrel lower tubular member 76, (FIG. 7B and FIG. 9), has a main bore 77 eccentrically disposed therein which communicates through the sub 36 with the bore 74 through the lower mandrel central tubular member 72. This eccentric bore 77 extends downwardly for a substantial distance in the lower tubular member 76 and terminates in the squeeze port 45 through the wall thereof.

A pair of lower cup-type oppositely facing packers 39, 40, upper packer opening downwardly, lower packer opening upwardly, are provided on the lower tubular member 76, with this pair of packers being of substantially identical construction and dimension as the aforesaid upper pair of packers 19, 20. This pair of packers is installed on the lower tubular member 76 with upper packer 39 disposed below the bypass port 38 therein which communicates with a longitudinally extending bore 78 drilled upwardly therein from the lower end thereof. Such packers are fixedly positioned upon the lower tubular member 76 by lock nuts 60a, 60b disposing the packers to bear against shoulders 61a, 61b in correspondence with the manner in which the packers 19, 20, hereinabove described, are mounted on the upper sleeve member 59 in FIG. 4A. Below the lock-nut 60b, FIG. 7B, a terminal lower mandrel sub 79 is threaded upon the lower tubular member 76 to complete the mandrel assembly. Also, in FIG. 7B an extension 41 of the tool from the lower mandrel assembly 30, is shown in the form of a tubular member threaded into the lower mandrel lower sub 79, and a hollow bull plug 42 (FIGS. 1 and 2) may be installed on this member 41, as in many conventional practices.

The usages and positions of the tool 16 have been described hereinabove with relation to the disclosure of FIGS. 1-3, inclusive, and as made more obvious by the detailed disclosure set forth in FIG. 4A through FIG. 10A, inclusive. Furthermore, an especial service that the tool 16 may render if the lower mandrel 30 hereinabove described is extended in length, as the lower mandrel 30a, FIGS. 11-14, inclusive. The object of increasing the length of the lower mandrel to the length disclosed is to space the packers 39, 40, substantially apart to increase the length of the "squeeze" space so as to serve some plurality of perforations. In such a case the tool on the lower end of the tubing string 10, is lowered into a well bore into the proximity of a perforated area of casing 11, (FIG. 3, perforations 46, 47, 80), and without setting the packer 20 to stretch the tubing string 10, the packers 39, 40 are first set in unperforated casing by pumping service fluid down the tubing string and tool and out the squeeze port 45. Then, with this test as a comparison the tubing string is lowered until it is indicated that at least one perforation or level of perforation is between the packers 39, 40, by the falling off of the service fluid pressure gauge at the top of the well. With this information the elevation of the tool may be adjusted in the well bore until it straddles a perforated area of casing length to be serviced. Then the service fluid is applied out of the squeeze port 45 to apply against the whole perforated area, the packers 39 and 40 being set.

With the tool disposed at a level in perforated casing where some perforations fall between the set packers 39, 40 and some are above the packer 39, the service fluid can pass out through the perforations between packers and move up the space 14 outwardly of the cement 13, and pass back into the cased well bore 11 through the perforations above the aforesaid packer 39, and rise in the casing annulus above the packer 39. Thus the upwardly opening, lower packer 20 of the upper pair of packers would remain unset, but the rising service fluid pressure will set the downwardly opening upper packer 19. The setting of the upper packer 19 thus establishes an upper barrier for the service fluid so as to limit the expansion of the total service fluid area now pressurized, whereby the casing wall between lower packers 39, 40, does not have to withstand service fluid pressure acting through a limited space, which a weak casing 11 might not be strong enough to sustain Rather, the area over which the force of the service fluid pump is applied, will be substantially increased, so that the service fluid pressure per square inch over such area can drop to a figure which does not jeopardize the well casing 11.

It often is the practice to reenforce the cup-type packers so that not one but a pair of downwardly facing or opening packers will be upwardly in tandem and not one but a pair of upwardly facing or opening packers will be downwardly in tandem. Such an arrangement can require a lower mandrel lower tubular member of greater length that the lower mandrel lower tubular member 76 (FIG. 7B), because of mounting four packers, but as above described, the tool functions as aforesaid.

Having a tandem, doubled, or reenforced packer arrangement as immediately hereinabove described, it is possible to convert the recover service fluid, by connecting a mandrel portion 81, FIG. 15, (corresponding in structure with a modified member 76, as shown in FIG. 7B), by means of a connecting mandrel sub 36, (also shown in FIG. 7B), directly to the lower end of a tubing string 10, as shown in FIG. 4A. In this arrangement the packer 40a is reversed to open upwardly, and a spacer or assembly ring 82 is installed on the mandrel 81 above the upper packer 40a. Then, when the lock nut 60a is threaded upon the mandrel 81 to bear upon the top surface of the spacer ring 82, the packer 39 therebelow, (the downwardly opening squeeze packer), bears upon the mandrel shoulder 61a, and the packers 40a, 39 are restrained in assembled position. It follows that threading the lock-nut 60b up on the mandrel 81 to abut the lock-nut 60a, assures locking of the assembly.

In similar manner the lower packer 39a is reversed to open downwardly, a spacer ring 82 being installed on the mandrel 81 below the lower packer 39a, with the lock-nut 60a being threaded upwardly on the mandrel 81 to bear upon the lower surface of the spacer ring 82. The packer 40 thereabove then bears upon the mandrel shoulder 61b, the packers 39a, 40 are thus restrained in assembled position, and when the lock-nut 60b is threaded up on the mandrel 81 to abut the lock-nut 60a, the lower pair of packers 40, 39a are locked in assembled position.

Now, obviously, if the tool 81 should be lowered by the tubing string to an area or length of perforated casing, if circulating fluid is pumped down the casing annulus, some will go to set the upward facing, upper packer 40a, some will pass into the bypass port 38 and down the bypass bore 78a, and into the well bore therebelow to set the lowermost, downwardly facing packer 39a, and some will pass from the casing annulus through upper perforations, and downwardly and back through perforations in areas opposite the squeeze port 45 and thereabove and therebelow, to set the oppositely facing, upper and lower squeeze packers 39, 40. Also, part of the circulating fluid that passages downwardly through the bore 78a will wash out through perforations therebelow in the casing, and then will pass upwardly and back into the casing annulus through perforations generally opposite the squeeze port 45, to participate with the fluid from above, and hereinabove described, in setting the squeeze packers 39, 40. Also it can be seen that the circulating fluid, as thus applied under pressure, can urge upon service fluid previously applied down the tubing string, and force this service fluid, through the port 45, to rise in the squeeze bore 77 and in the tubing string to the top of the well.

The construction of the mandrel 81 is shown as divided into an upper part 81a, a central part 81b, and a lower part 81c for ease and practicality of assembly. Also, various changes in machine design and shop practice may be made, and the tool may be designed in other ways in practicality with the broad accomplishments of the tool, and the extensive method steps at which it may be used successfully.

Claims

We claim:

1. In combination with a well tubing string insertable into a casing providing perforations therein at at least one substantially predetermined location, a well tool comprising a hollow mandrel having an open lower end and connected upwardly to the tubing string lower end, said mandrel providing openings successively longitudinally spaced apart therebelow, namely: a longitudinally extending, outwardly opening, equalizing passage, also a circulating opening from the hollow mandrel, also a bypass port into a bypass channel communicating with the mandrel open lower end, and a squeeze port from said hollow mandrel above said lower end with a pair of oppositely facing cup type packers on said mandrel, one downwardly facing above, and the other upwardly facing below said squeeze port, said mandrel also having a lower sleeve thereon clutch engageable therewith, said lower sleeve also having a lower, yieldably, outwardly urged friction means thereon and a circulating port therethrough at circulating opening level, an upper sleeve on said mandrel clutch engageable therewith and mounting downwardly facing cup type packer means thereon, with equalizing ports in said upper sleeve disposed one above and one below said cup type packer means, said mandrel also having an upper, yieldably outwardly urged friction means thereon, clutch engageable with said upper sleeve and spaced below said cup-type packer means, upon relative rotation between mandrel and upper sleeve in one direction said equalizing ports communicating with said equalizing passage and said circulating opening communicating with said circulating port, and upon relative rotation between mandrel and upper sleeve in the opposite direction, said equalizing ports and said circulating ports being closed, whereby service fluid from squeeze port may set said lower pair of packers, wash through said perforations and upwardly and back into the casing annulus and upwardly to set said downwardly facing cup-type packer on said upper sleeve.

2. The combination as claimed in claim 1, in which said cup-typer packer means at least comprises an upwardly opening packer whereby pressurized circulating fluid applied downwardly in the casing annulus may set the comprised upwardly opening packer to dam the casing annulus so that the application of the pressurized circulating fluid may stretch the tubing string in length to extend downwardly from a substantially predetermined position above the casing perforations to dispose said squeeze port at elevation to deliver service fluid pumped down the tubing string and hollow mandrel to wash through the uppermost casing perforation.

3. The combination as claimed in claim 1, in which said cup type packer means at least comprises a downwardly opening packer whereby, with said tool disposed to deliver service fluid through said squeeze port and lower perforations to pass back through perforations thereabove into the casing annulus, said downwardly opening packer sets to dam the casing annulus against further expansion of the service space and consequent loss of service space pressure.

4. The combination as claimed in claim 1, in which said cup type packer means comprises an upper, downwardly opening, cup type packer and a lower, upwardly opening, cup type packer.

5. The combination as claimed in claim 1 in which said hollow mandrel includes a lower threaded end and hollow extension means of selective length threadably engageable with said lower end and adapted to have the lower, upwardly opening packer of said pair mounted thereon at level to establish a predetermined distance between the packers of said pair whereby to establish a predetermined casing annulus service space through which to service the perforations.

6. The method of servicing down well casing perforations with a well tool on the end of a tubing string, comprising the steps of lowering the tool into the casing, with fluid circulation therethrough equalized, to a selective position above an upper perforation, pressurizing the casing annulus fluid against a first dam provided on the tool thereby to stretch the tubing string, as it is held at the top of the well, to dispose the tool in squeeze position with relation to the upper perforation, and pumping service fluid under pressure down the tubing string and out from the tool into a limited area whereby the pressurized fluid reacts against tool parts to establish a dam above and below the squeeze port and straddling the said upper perforation, whereby to wash service fluid outwardly therethrough, and successively lowering the tubing string predetermined distances between successively lower perforations as the casing annulus fluid against the first dam holds the tubing string stretched, thereby to service successive perforations.

7. The method of servicing an extent of vertical area of a perforated well casing comprising the steps of, lowering a well tool on the lower end of a tubing string into the well bore and circulating service fluid down the well tubing string and out through the tool into the casing annulus to cooperate with the tool to establish substantially spaced apart dams across the casing annulus above and below the fluid outlet from the tool, urging the circulated service fluid to wash outwardly through the perforations and passing part of the urged service fluid upwardly and back through previously serviced perforations into the casing annulus and upwardly to cooperate with the tool to establish an upper barrier for the circulated fluid, thus to delimit total pressurized service space and thereby limiting the applied pressure thereof.

8. The method of back servicing through an extent of vertical area of a perforated well casing comprising the steps of lowering a well tool on the lower end of a tubing string into the well bore and within the perforated area of the perforated well casing, delivering a circulating fluid down the casing annulus to cooperate with the tool to establish an upper dam across the annulus, bypassing part of the circulating fluid from above the first dam and out the lower end of the tool to cooperate with the tool to establish a lower dam across the annulus, the circulating fluid from above the upper dam and from below the lower dam being urged outwardly of perforations and respectively downwardly and upwardly to return through previously serviced perforations into the cased well bore to set the dams across the casing annulus that are disposed intermediate the aforesaid intermediate dams and thus to urge the service fluid from between the intermediate dams back up the tool and the tubing string.

9. In combination with a well tubing string insertable into a casing providing perforations therein at at least one substantially predetermined location, a well tool comprising a hollow mandrel having an open lower end and connected upwardly to the tubing string lower end, said mandrel providing openings successively longitudinally spaced apart therebelow, namely: a longitudinally extending, outwardly opening, equalizing passage, also a circulating opening from the hollow mandrel, also a bypass port into a bypass channel communicating with the mandrel open lower end, and a squeeze port from said hollow mandrel above said lower end, a tubular extension connected to communicate with said mandrel lower end to extend therebelow, a lower pair of oppositely facing cup type packers, one on said mandrel between bypass port and squeeze port and facing downwardly, the other on said tubular extension above the lower end thereof and facing upwardly, said mandrel also having a lower sleeve thereon clutch engageable therewith, said lower sleeve also having a lower, yieldably, outwardly urged friction means thereon and a circulating port therethrough at circulating opening level, an upper sleeve on said mandrel clutch engageable therewith and mounting downwardly facing cup type packer means thereon, an equalizing port in said upper sleeve above and below said cup type packer means, said mandrel also having an upper, yieldably outwardly urged friction means thereon, clutch engageable with said upper sleeve and spaced below said cup type packer means, upon relative rotation between mandrel and upper sleeve in one direction said circulating opening communicating with said circulating port, and upon relative rotation between mandrel and upper sleeve in the opposite direction, said equalizing ports and said circulating ports being closed, whereby service fluid from squeeze port may set said lower pair of packers, wash through said perforations and upwardly and back into the casing annulus and upwardly to set said downwardly facing cup type packer on said upper sleeve.

10. In combination with a cased well bore tubing string insertable into a casing providing perforations therein over a predetermined vertical range, a well tool comprising a hollow mandrel having an open lower end and connected upwardly to the tubing string lower end, said mandrel providing openings successively longitudinally spaced apart therebelow, namely: a bypass port into a bypass channel communicating with the mandrel open lower end, also an upper pair of back-to-back, cup-type packers, the upper packer of the pair opening upwardly, and the lower packer of the pair opening downwardly, also a squeeze port into a squeeze channel communicating with the tubing string interior thereabove, and a lower pair of back-to-back, cup type packers below said squeeze port and above said mandrel open lower end, the upper packer of the pair opening upwardly, and the lower packer of the pair opening downwardly, whereby with perforations opposite, above and below said packers, circulating fluid may be pumped down the casing annulus around the tubing string and well tool to set the upper packer of the upper pair, to circulate from casing annulus through perforations and downwardly and back through perforations into the casing annulus to set oppositely facing intermediate packers and to urge service fluid recovery back into said squeeze port and the squeeze channel upwardly through the tubing string, also to circulate into the by-pass port and down the bypass channel to set the lower packer of the upper pair, also to circulate outwardly through perforations and upwardly and back through perforations into the casing annulus to set oppositely facing intermediate packers and to urge service fluid recovery as aforesaid.