Method and apparatus for cementing production tubing in a multilateral borehole

A hydraulically actuated anchor and a mechanically actuated packer are used in combination to secure a production tubing system in a lateral prior to injection of a cement to line the lateral borehole in which the production tubing is positioned. The packer is expanded to prevent fluid cement material from flowing past the packer into a junction area of the lateral with other laterals and aid the removal of superfluous cement material after hardening of the injected cement material around the production tubing system.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates generally to a method and apparatus for cementing production tubing in a multilateral borehole, and more specifically to such a method and apparatus wherein cement used for lining the borehole does not block adjacently disposed laterals.

2. Background of the Invention

Directional drilling has recently become increasingly important in the oil industry as a cost effective alternative to vertical drilling because this technique significantly improves production. To further increase production, one or more lateral wellbores may be drilled, with the greatest production being achieved from a multilateral well. Due to this increased dependence on horizontal wells, problems with lateral completion have been a growing concern.

Multilateral boreholes are commonly used to increase the production from a defined hydrocarbon production zone. The term “lateral,” as used herein and in the claims, means a branch borehole extending generally radially outwardly from a pilot, or main, well borehole. The radially outwardly extending branches may be horizontally oriented or erected at a diagonal angle with respect to the axis of the main well borehole. Although not as common, the term “lateral” also includes a lateral mixed in from a preexisting lateral-that is, a lateral may be a branch off of an earlier-formed lateral.

Heretofore a problem with cementing multilateral boreholes has been that cement used to line the borehole can extrude backwardly through the borehole and block the junction of adjacent laterals with the main well borehole. For example, in the parent application of this application, a liner hanger for the production tubing extending into the lateral was placed in the main production casing of the primary wellbore and cement injected for lining around the production tubing in the lateral would fill the lateral and portion of the main well borehole up to the vicinity of the liner hanger. When multilateral boreholes are formed, if cement extrudes backwardly through the lateral being lined into the junction of an adjacent lateral, that cement will plug the junction and prevent production tubing from later being placed and cemented into the adjacent lateral.

The present invention is directed to overcoming the problem outlined above. It is desirable to have a method and apparatus for cementing production tubing into a lateral without blocking adjacently-formed laterals with the cement lining material. It is also desirable to have such a method and apparatus wherein the liner hanger is positioned in the lateral being lined and the cement lining prevented from backflowing any significant amount beyond the hanger.

SUMMARY OF THE INVENTION

In accordance with one aspect of the present invention, a method for cementing production lining in a multilateral borehole includes running production tubing into the lateral and setting an anchor spaced from a distal end of the production tubing so that the production tubing is secured in a fixed relationship with the lateral. A fluid cement material is injected through the production tubing and around an annular space around the production tubing between the external surface of the tubing and an internal surface of the lateral. The injecting of the fluid cement material is continued for a period of time sufficient to substantially fill the annular space around the production tubing from the distal end of the tubing to a packer positioned in the lateral and spaced from the distal end of the tubing. The packer is then set so that a seal is formed between the production tubing and the internal surface of the lateral.

Other features of the method for cementing production tubing in a multilateral borehole include subsequently removing fluid cement material deposits from the production tubing. Another feature subsequent to removing fluid cement material from the production tubing includes disconnecting a working tubing section from a distal end of the packer and flushing the borehole so that any residual fluid cement material from the borehole and junctions with other laterals is removed.

Still other features for the method for cementing production tubing in accordance with the present invention include hydraulically expanding at least one radially outwardly movable member of the anchor and mechanically expanding at least one radially outwardly movable member of the packer.

In another aspect of the present invention, a production tubing system adapted for fixed installation in a lateral of a multilateral borehole includes a gathering tubing section having a distal end adapted for positioning at an end of the lateral and a proximal end spaced from the distal end. The tubing system includes a hydraulically actuatable anchor having a first end connected to the proximal end of the gathering tubing section and a mechanically actuatable packer having a first end operably connected to a second end of the anchor. A working tubing section is removably attached to a second end of the packer.

Other features of the production tubing system embodying the present invention include the system having a tubing section positioned between the anchor and the packer.

Another feature of the production tubing system embodying the present invention includes the mechanically actuatable packer having at least one radially outwardly expandable seal member that is expandable only after the hydraulically actuatable anchor is actuated.

In another aspect of the present invention, an anchor-packer for use in a production tubing installation in a lateral includes a hydraulically actuatable anchor section that is attachable to a section of gathering tubing in a mechanically actuatable packer section that is attachable to a section of working tubing. The anchor-packer embodying the present invention also has at least one radially outwardly expandable seal member that is expandable only after actuation of the hydraulically actuatable anchor section.

Other features of the anchor-packer embodying the present invention include a centralizer that is adapted for connection between the anchor section and the gathering tubing and another centralizer interposed between the anchor section and the packer section.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

A cemented open hole selective fracing system is pictorially illustrated inFIG. 1. A production well10is drilled in the earth12to a hydrocarbon production zone14. A casing16is held in place in the production well10by cement18. At the lower end20of production casing16is located liner hanger22. Liner hanger22may be either hydraulically or mechanically set.

Below liner hanger22extends production tubing24. To extend laterally, the production well10and production tubing24bends around a radius26. The radius26may vary from well to well and may be as small as 30 feet and as large as 400 feet. The radius of the bend in production well10and production tubing24depends upon the formation and equipment used.

Inside of the hydrocarbon production zone14, the production tubing24has a series of sliding valves pictorially illustrated as28athru28h. The distance between sliding valves28athru28hmay vary according to the preference of the particular operator. A normal distance is the length of a standard production tubing of 30 feet. However, the production tubing segments30athru30hmay vary in length depending upon where the sliding valves28should be located in the formation.

The entire production tubing24, sliding valves28, and the production tubing segments30are all encased in cement32. Cement32located around production tubing24may be different from the cement18located around the casing16.

In actual operation, sliding valves28athru28hmay be opened or closed with a shifting tool as will be subsequently described. The sliding valves28athru28hmay be opened in any order or sequence.

For the purpose of illustration, assume the operator of the production well10desires to open sliding valve28h. A shifting tool34, such as that shown inFIG. 2, connected on shifting string would be lowered into the production well10through casing16and production tubing24. The shifting tool34has two elements34aand34bthat are identical, except they are reversed in direction and connected by a shifting string segment38. While the shifting string segment38is identical to shifting string36, shifting string segment38provides the distance that is necessary to separate shifting tools34aand34b. Typically, the shifting string segment38would be about 30 feet in length.

To understand the operation of shifting tool34inside sliding valves28, an explanation as to how the shifting tool34and sliding valves28work internally is necessary. Referring toFIG. 3, a partial cross-sectional view of the sliding valve28is shown. An upper housing sub40is connected to a lower housing sub42by threaded connections via the nozzle body44. A series of nozzles46extend through the nozzle body44. Inside of the upper housing sub40, lower housing sub42, and nozzle body44is an inner sleeve48. Inside of the inner sleeve48are slots that allow fluid communication from the inside passage52through the slots50and nozzles46to the outside of the sliding valve28. The inner sleeve48has an opening shoulder54and a closing shoulder56located therein.

When the shifting tool34shown inFIG. 4goes into the sliding valve28, shifting tool34aperforms the closing function and shifting tool34bperforms the opening function. Shifting tools34aand34bare identical, except reverse and connected through the shifting string segment38.

Assume the shifting tool34is lowered into production well10through the casing16and into the production tubing24. Thereafter, the shifting tool34will go around the radius26through the shifting valves28and production pipe segments30. Once the shifting tool34bextends beyond the last sliding valve28h, the shifting tool34bmay be pulled back in the opposite direction as illustrated inFIG. 5Ato open the sliding valve28, as will be explained in more detail subsequently.

Referring toFIG. 3, the sliding valve28has wiper seals58between the inner sleeve48and the upper housing sub42and the lower housing sub44. The wiper seals58keep debris from getting back behind the inner sleeve48, which could interfere with its operation. This is particularly important when sand is part of the fracing fluid.

Also located between the inner sleeve48and nozzle body44is a C-clamp60that fits in a notch undercut in the nozzle body44and into a C-clamp notch61in the outer surface of inner sleeve48. The C-clamp puts pressure in the notches and prevents the inner sleeve48from being accidentally moved from the opened to closed position or vice versa, as the shifting tool is moving there through.

Also, seal stacks62and64are compressed between (1) the upper housing sub40and nozzle body44and (2) lower housing sub42and nozzle body44, respectively. The seal stacks62and64are compressed in place and prevent leakage from the inner passage52to the area outside sliding valve28when the sliding valve is closed.

Turning now to the shifting tool34, an enlarged partial cross-sectional view is shown inFIG. 4. Selective keys66extend outward from the shifting tool34. Typically, a plurality of selective keys66, such as four, would be contained in any shifting tool34, though the number of selective keys66may vary. The selective keys66are spring loaded so they normally will extend outward from the shifting tool34as is illustrated inFIG. 4. The selective keys66have a beveled slope68on one side to push the selective keys66in, if moving in a first direction to engage the beveled slope68, and a notch70to engage any shoulders, if moving in the opposite direction. Also, because the selective keys66are moved outward by spring72, by applying proper pressure inside passage74, the force of spring72can be overcome and the selective keys66may be retracted by fluid pressure applied from the surface.

Referring now toFIG. 5A, assume the opening shifting tool34bhas been lowered through sliding valve28and thereafter the direction reversed. Upon reversing the direction of the shifting tool34b, the notch70in the shifting tool will engage the opening shoulder54of the inner sleeve48of sliding valve28. This will cause the inner sleeve48to move from a closed position to an opened position as is illustrated inFIG. 5A. This allows fluid in the inside passage58to flow through slots50and nozzles46into the formation around sliding valve28. As the inner sleeve48moves into the position as shown inFIG. 5A, C-clamp60will hold the inner sleeve48in position to prevent accidental shifting by engaging one of two C-clamp notches61. Also, as the inner sleeve48reaches its open position and C-clamp60engages, simultaneously the inner diameter59of the upper housing sub40presses against the slope76of the selective key66, thereby causing the selective keys66to move inward and notch70to disengage from the opening shoulder54.

If it is desired to close a sliding valve28, the same type of shifting tool will be used, but in the reverse direction, as illustrated inFIG. 5B. The shifting tool34ais arranged in the opposite direction so that now the notch70in the selective keys66will engage closing shoulder56of the inner sleeve48. Therefore, as the shifting tool34ais lowered through the sliding valve28, as shown inFIG. 5B, the inner sleeve48is moved to its lowermost position and flow between the slots50and nozzles46is terminated. The seal stacks62and64insure there is no leakage. Wiper seals58keep the crud from getting behind the inner sleeve48.

Also, as the shifting tool34A moves the inner sleeve48to its lowermost position, pressure is exerted on the slope76by the inner diameter61of lower housing sub42of the selective keys66to disengage the notch70from the closing shoulder56. Simultaneously, the C-clamp60engages in another C-clamp notch61in the outer surface of the inner sleeve48.

If the shifting tool34, as shown inFIG. 2, was run into the production well10as shown inFIG. 1, the shifting tool34and shifting string36would go through the internal diameter of casing16, internal opening of hanger liner22, through the internal diameter of production tubing24, as well as through sliding valves28and production pipe segments30. Pressure could be applied to the internal passage74of shifting tool34through the shifting string36to overcome the pressure of springs72and to retract the selective keys66as the shifting tool34is being inserted. However, on the other hand, even without an internal pressure, the shifting tool34b, due to the beveled slope68, would not engage any of the sliding valves28athru28has it is being inserted. On the other hand, the shifting tool34awould engage each of the sliding valves28and make sure the inner sleeve48is moved to the closed position. After the shifting tool34bextends through sliding valve28h, shifting tool34bcan be moved back towards the surface causing the sliding valve28hto open. At that time, the operator of the well can send fracing fluid through the annulus between the production tubing24and the shifting string36. Normally, an acid would be sent down first to dissolve the acid soluble cement32around sliding valve28(seeFIG. 1). After dissolving the cement32, the operator has the option to frac around sliding valve28h, or the operator may elect to dissolve the cement around other sliding valves28athru28g. Normally, after dissolving the cement32around sliding valve28h, then shifting tool34awould be inserted there through, which closes sliding valve28h. At that point, the system would be pressure checked to insure sliding valve28hwas in fact closed. By maintaining the pressure, the selective keys66in the shifting tool34will remain retracted and the shifting tool34can be moved to shifting valve28g. The process is now repeated for shifting valve28g, so that shifting tool34bwill open sliding valve28g. Thereafter, the cement32is dissolved, sliding valve28gclosed, and again the system pressure checked to insure valve28gis closed. This process is repeated until each of the sliding valves28athru28hhas been opened, the cement dissolved, pressure checked after closing, and now the system is ready for fracing.

By determining the depth from the surface, the operator can tell exactly which sliding valve28athru28his being opened. By selecting the combination the operator wants to open, then fracing fluid can be pumped through casing16, production tubing24, sliding valves28, and production tubing segments30into the formation.

By having a very limited area around the sliding valve28that is subject to fracing, the operator now gets fracing deeper into the formation with less fracing fluid. The increase in the depth of the fracing results in an increase in production of oil or gas. The cement32between the respective sliding valves28athru28hconfines the fracing fluids to the areas immediately adjacent to the sliding valves28athru28hthat are open.

Any particular combination of the sliding valves28athru28hcan be selected. The operator at the surface can tell when the shifting tool34goes through which sliding valves28athru28hby the depth and increased force as the respective sliding valve is being opened or closed.

Applicant has just described one type of mechanical shifting of mechanical shifting to34. Other types of shifting tools may be used including electrical, hydraulic, or other mechanical designs. While shifting tool34is tried and proven, other designs may be useful depending on how the operator wants to produce the well. For example, the operator may not want to separately dissolve the cement32around each sliding valve28, and pressure check, prior to fracing. The operator may ant to open every third sliding valve28, dissolve the cement, then frac. Depending upon the operator preference, some other type shifting tool may be easily be used.

Another aspect of the invention is to prevent debris from getting inside sliding valves28when the sliding valves28are being cemented into place inside of the open hole. To prevent the debris from flowing inside the sliding valve28, a plug78is located in nozzle46. The plug78can be dissolved by the same acid that is used to dissolve the cement32. For example, if a hydrochloric acid is used, by having a weep hole80through an aluminum plug78, the aluminum plug78will quickly be eaten up by the hydrochloric acid. However, to prevent wear at the nozzles46, the area around the aluminum plus78is normally made of titanium. The titanium resists wear from fracing fluids, such as sand.

While the use of plug78has been described, plugs78may not be necessary. If the sliding valves28are closed and the cement32does not stick to the inner sleeve48, plugs78may be unnecessary. It all depends on whether the cement32will stick to the inner sleeve48.

Further, the nozzle46may be hardened any of a number of ways instead of making the nozzles46out of Titanium. The nozzles46may be (a) heat treated, (b) frac hardened, (c) made out of tungsten carbide, (d) made out of hardened stainless steel, or (e) made or treated any of a number of different ways to decrease and increase productive life.

Assume the system as just described is used in a multi-lateral formation as shown inFIG. 6. Again, the production well10is drilled into the earth12and into a hydrocarbon production zone14, but also into hydrocarbon production zone82. Again, a liner hanger22holds the production tubing24that is bent around a radius26and connects to sliding valves28athru28h, via production pipe segments30athru30h. The production of zone14, as illustrated inFIG. 6, is the same as the production as illustrated inFIG. 1. However, a window84has now been cut in casing16and cement18so that a horizontal lateral86may be drilled there through into hydrocarbon production zone82.

In the drilling of multi-lateral wells, an on/off tool88is used to connect to the stinger90on the liner hanger22or the stinger92on packer94. Packer94can be either a hydraulic set or mechanical set packer to the wall81of the horizontal lateral86. In determining which lateral86or96, the operator is going to connect to, a bend98in the vertical production tubing100helps guide the on/off tool88to the proper lateral86or96. The sliding valves102athru102gmay be identical to the sliding valves28athru28h. The only difference is sliding valves102athru102gare located in hydrocarbon production zone82, which is drilled through the window84of the casing16. Sliding valves102athru102gand production tubing104athru104gare cemented into place past the packer94in the same manner as previously described in conjunction withFIG. 1. Also, the sliding valves102athru102gare opened in the same manner as sliding valves28athru28has described in conjunction withFIG. 1. Also, the cement106may be dissolved in the same manner.

Just as the multi laterals as described inFIG. 6are shown in hydrocarbon production zones14and82, there may be other laterals drilled in the same zones14and/or82. There is no restriction on the number of laterals that can be drilled nor in the number of zones that can be drilled. Any particular sliding valve may be operated, the cement dissolved, and fracing begun. Any particular sliding valve the operator wants to open can be opened for fracing deep into the formation adjacent the sliding valve.

By use of the system as just described, more pressure can be created in a smaller zone for fracing than is possible with prior systems. Also, the size of the tubulars is not decreased the further down in the well the fluid flows. The decreasing size of tubulars is a particular problem for a series of ball operated valves, each successive ball operated valve being smaller in diameter. This means the same fluid flow can be created in the last sliding valve at the end of the string as would be created in the first sliding valve along the string. Hence, the flow rates can be maintained for any of the selected sliding valves28athru28hor102athru102g. This results in the use of less fracing fluid, yet fracing deeper into the formation at a uniform pressure regardless of which sliding valve through which fracing may be occurring. Also, the operator has the option of fracing any combination or number of sliding valves at the same time or shutting off other sliding valves that may be producing undesirables, such as water.

On the top of casing18of production well10is located a wellhead108. While many different types of wellheads are available, the wellhead preferred by applicant is illustrated in further detail inFIG. 7. A flange110is used to connect to the casing16that extends out of the production well10. On the sides of the flange110are standard valves112that can be used to check the pressure in the well, or can be used to pump things into the well. A master valve114that is basically a float control valve provides a way to shut off the well in case of an emergency. Above the master valve114is a goat head116. This particular goat head116has four points of entry118, whereby fracing fluids, acidizing fluids or other fluids can be pumped into the well. Because sand is many times used as a fracing fluid and is very abrasive, the goat head116is modified so sand that is injected at an angle to not excessively wear the goat head. However, by adjusting the flow rate and/or size of the opening, a standard goat head may be used without undue wear.

Above the goat head116is located blowout preventer120, which is standard in the industry. If the well starts to blow, the blowout preventer120drives two rams together and squeezes the pipe closed. Above the blowout preventer120is located the annular preventer122. The annular preventer122is basically a big balloon squashed around the pipe to keep the pressure in the well bore from escaping to atmosphere. The annular preventer122allows access to the well so that pipe or tubing can be moved up and down there through. The equalizing valve124allows the pressure to be equalized above and below the blow out preventer120. The equalizing of pressure is necessary to be able to move the pipe up and down for entry into the wellhead. All parts of the wellhead108are old, except the modification of the goat head116to provide injection of sand at an angle to prevent excessive wear. Even this modification is not necessary by controlling the flow rate.

Turning now toFIG. 8, the system as presently described has been installed in a well126without vertical casing. Well126has production tubing128held into place by cement130. In the production zone132, the production tubing128bends around radius134into a horizontal lateral136that follows the production zone132. The production tubing128extends into production zone132around the radius134and connects to sliding valves38athru38f, through production tubing segments140athru140f. Again, the sliding valves138athru138fmay be operated so the cement130is dissolved therearound. Thereafter, any of a combination of sliding valves138athru138fcan be operated and the production zone132fraced around the opened sliding valve. In this type of system, it is not necessary to cement into place a casing nor is it necessary to use any type of packer or liner hanger. The minimum amount of hardware is permanently connected in well126, yet fracing throughout the production zone132in any particular order as selected by the operator can be accomplished by simply fracing through the selected sliding valves138athru138f.

The system previously described can also be used for well140that is entirely vertical as shown inFIG. 9. The wellhead108connects to casing144that is cemented into place by cement146. At the bottom147of casing144is located a liner hanger148. Below liner hanger148is production tubing150. In the well144, as shown inFIG. 9, there are producing zones152,154, and156. After the production tubing150and sliding valves158,160, and162athru162dare cemented into place by acid soluble cement164, the operator may now produce all or selected zones. For example, by dissolving the cement164adjacent sliding valve158, thereafter, production zone152can be fraced and produced through sliding valve158. Likewise, the operator could dissolve the cement164around sliding valve160that is located in production zone154. After dissolving the cement164around sliding valve160, production zone154can be fraced and later produced.

On the other hand, if the operator wants to have multiple sliding valves162athru162doperate in production zone156, the operator can operate all or any combination of the sliding valves162athru162d, dissolve the cement164therearound, and later frac through all or any combination of the sliding valves162athru162d. By use of the method as just described, the operator can produce whichever zone152,154or156the operator desires with any combination of selected sliding valves158,160or162.

By use of the method as just described, the operator, by cementing the sliding valves into the open hole and thereafter dissolving the cement, fracing can occur just in the area adjacent to the sliding valve. By having a limited area of fracing, more pressure can be built up into the formation with less fracing fluid, thereby causing deeper fracing into the formation. Such deeper fracing will increase the production from the formation. Also, the fracing fluid is not wasted by distributing fracing fluid over a long area of the well, which results in less pressure forcing the fracing fluid deep into the formation. In fracing over long areas of the well, there is less desirable fracing than what would be the case with the present invention.

The above-description illustrates the selective fracing system embodying the present invention with respect to a single open hole. However, as described above, directional drilling has recently become increasingly important to the oil industry. In directional drilling, one or more lateral wellbores are drilled to further increase production with the greatest production being achieved in a multilateral well. In multilateral wells, such as illustrated inFIG. 6, it can been seen that cement can extrude back through the production well to a point where it impinges on or enters into another lateral, making it impossible to later use that lateral either for the placement of production tubing or placement and cementing in of production tubing or extraction of hydrocarbon from the plugged lateral.

FIG. 10shows a side view of the preferred embodiment of the present invention. An open hole packer202and an open hole anchor204are provided on either end of a tubing section206, which is a section of production pipe inserted to make the assembly more limber and easier to run down a well. A pair of centralizers201are located at the bottom and middle of the anchor-packer to keep it positioned concentrically in a wellbore and to hold the anchor-packer off the bottom of a lateral, thus protecting the anchor-packer as it is run into the production well. In addition, the centralizers201push debris ahead of the anchor-packer as it is run into the wellbore. An on/off connector200allows a work string207to be attached to the packer202(seeFIG. 17), and is used to mechanically set the packer202by rotating the work string207. When set, the packer202forms a seal between an outer surface of the packer202and a wall300of a lateral26, as illustrated inFIG. 17, thus isolating the lateral26from any fluids and pressures applied from above the packer202. The anchor204keeps the anchor-packer in a stationary position so that compression weight can be applied to the packer202for setting and other purposes at the appropriate times.

FIG. 11is a perspective view of the anchor204in the preferred embodiment of the present invention, whileFIG. 12shows a side view of the anchor204. The anchor204provides a tubing section208positioned adjacent a jam nut212. A plurality of set screws210fasten the tubing section208to the jam nut212, thus preventing the tubing section208from sliding relative to the jam nut212. An upper piston stop214is positioned between the jam nut212and an outer cylinder228, and secured in place by a plurality of set screws216. A lock housing240is fastened to the outer cylinder228by a plurality of screws238(seeFIG. 13). A partially enclosed lower piston230protrudes from the outer cylinder228and the lock housing240, providing a threaded means for connection of an upper cone244. A slip cage248, which is screwed into a slip cage cap242, is positioned around the upper cone244with an inclined surface244a, slips246with lower slip faces246b, and a portion of a lower cone250, which has an inclined surface250a. Until and if a well operator removes the invention from the wellbore, the lower cone250is fastened to a mandrel254by shear pins252. As shown inFIG. 12, torque pins256prevent the slip cage248and slips246from spinning relative to the upper cone244.

FIG. 13shows a longitudinal section taken along the line13-13ofFIG. 12. To set the anchor204in the wall300of the lateral26(seeFIG. 17), a plug is first run below the assembly to allow the buildup of fluid pressure when fluid is pumped down the well. Fluid is then pumped inside the anchor204through the tubing section208. As the plug resists fluid flow, fluid leaves the mandrel254through a plurality of holes227, filling a chamber231between the upper piston220and the lower piston230, enclosed by the mandrel254and the outer cylinder228. Lower o-rings224and upper o-rings226, a pair of each of which is located on both the upper piston220and lower piston230, prevent fluid from leaving the chamber231, and as fluid pressure inside the chamber231increases, the lower piston230is forced down the anchor204toward the upper cone244.

As the lower piston230moves down the anchor204, a lock236engages the lower piston230by dropping into one of a plurality of lock notches233, thus preventing the lower piston230from moving up the mandrel254toward the upper piston220. Each lock notch233is configured in such a manner so as to allow the lock236to easily move out of the lock notch233as the lower piston230moves down the mandrel254, but to force the lock236to remain in the lock notch233to resist any movement of the lower piston230up the mandrel254. Thus, the lock236engages the lock notches233of the lower piston230such that the lower piston230can only be moved down the mandrel254toward the upper cone244.

As the lower piston230moves down the mandrel254, the upper cone244, which is threaded to the lower piston230, also moves down the mandrel254. Because the slips246are supported by the slip cage248and the slip cage248is supported by the upper cone244, as the upper cone244moves down the mandrel254, the slips246and slip cage248also move down the mandrel254. As the lower slip face246bcontacts the lower cone250, the inclined surface250aof the lower cone250exerts a radially outward force on the slips246, causing the slips246to move away from the mandrel254and toward the wall300of the open lateral26(seeFIG. 17). The slip teeth246athus engage the wall300of the open lateral26(seeFIG. 17), securing the anchor204and attached assembly against movement upwardly or downwardly in the hole.

A well operator could later unset the anchor204by exerting a compression force on the anchor204in excess of the shear strength of the shear pins252, which would break the shear pins252, allowing the lower cone250to move down the mandrel254and away from the upper cone244. The weight of the slips246and force exerted on the slips246by the wall300of the lateral26(seeFIG. 17) push the slips246away from the wellbore and toward the mandrel254. As the lower slip face246bpushes the inclined surface250aof the lower cone250, the lower cone250is free to move along the mandrel254. The slips246thus recede from the wall300of the lateral26(seeFIG. 17) and into the slip cage248, and the anchor204and assembly can be moved along the lateral26(seeFIG. 17). The anchor204, however, cannot be reset without replacing the shear pins252to once again restrict the movement of the lower cone250relative to the mandrel254.

FIG. 14depicts a perspective view of the open hole packer202of a preferred embodiment of the present invention, whileFIG. 15shows a side view of the packer202. A plurality of shear pins262fasten a lock housing272to the mandrel282adjacent a thimble adapter266, to which is attached an upper thimble270. A shear ring278is fastened to the mandrel282by a plurality of shear pins263. Between the shear ring278and the upper thimble270are two rubber seals276separated by a spacer274. Neither the rubber seals276nor the spacer274are fastened to the mandrel282.

FIG. 16is a longitudinal cross section ofFIG. 15along section lines16-16and shows how the packer202can be set and then, if so desired, later released. After the anchor204, shown inFIGS. 10 through 13, has been set, a well operator causes enough compression force on the lock housing272of the packer202to shear the shear pins262. After the shear pins262break, the operator can move the lock housing272, thimble adaptor266, and upper thimble270along the mandrel282toward the rubber seals276. A lock264, however, allows movement in only this direction, and prevents these elements from moving up the mandrel282toward a top connection258. A split ring268is positioned in a groove269of the mandrel282and acts as a mechanical stop to keep the upper thimble270from moving past the split ring268. As an external force moves the lock housing272, the thimble adaptor266, and the upper thimble270toward the rubber seals276, the thimble adaptor270compresses the rubber seals276along their cylindrical axes, causing the rubber seals276to bulge radially outward from the mandrel282and into the wall300of the lateral26(see FIG.17). This seals the well at the point of the packer202, and more specifically at the point of the rubber seals276, from the backflow of gas, fluid, or cement.

If it is later desired to unset the rubber seals276, a well operator causes enough compression force on the lock housing272, which is then transmitted through the thimble adaptor266, the upper thimble270, the rubber seals276, and the shear ring278, to shear the shear pins263. After the shear pins263break, the shear ring278is pushed down the mandrel282by the rubber seals276, which return to their unstressed and uncompressed state. This breaks the seal between the packer202and the wall300of the lateral26(seeFIG. 17). The shear strength of the downwell shear pins263is greater than the shear strength of the upwell shear pins262to avoid shearing both sets of pins when setting the packer202.

FIG. 17shows production tubing sections304a,304b, representative of the present invention, installed and being installed in a multilateral production well10. The production well10is drilled into the earth12to a hydrocarbon production zone14. A well operator controls operation of the well through wellhead108, which attaches to a production casing16at the surface. This allows for a well operator to perform normal production functions, such as check the pressure in the well or pump fluid into the well.

At the lower end of the production casing16, the work string207protrudes through the casing16and into the production zone14. In the production zone14are drilled an upper lateral24, in which a production tubing system304aembodying the present invention has been previously installed, and a lower lateral26, in which a production tubing system304bembodying the present invention is being installed. Fluid cement material500lines the wellbore along the upper lateral24and will harden over time.

In carrying out the method for cementing production tubing in a predefined lateral26of a multilateral production well10, production tubing, or more specifically the production tubing system304bembodying another aspect of the present invention, is run into the lower lateral26until the anchor204and the packer202are advanced beyond a junction400of the upper lateral24with the lower lateral26. In carrying out the present invention, it should be noted that either earlier- or later-formed laterals may branch off of the main wellbore instead of another lateral. After the production tubing section304bis run into the lateral26, it is secured in place by setting the anchor204as a result of expanding the slips246(seeFIGS. 12,13) and engaging the slip teeth246a(seeFIGS. 12,13) against the wall300of the open lateral26, as described above. A fluid cement material500is injected through the internal bore of the packer202and the anchor204and through a gathering section210. The fluid cement material500may be discharged from the production tubing system304bthrough an opening at a distal end212of the gathering section210, through openings at one or more sliding valves28as described above, or through other openings provided either before installation of the gathering section210or subsequently formed after installation in the lateral26. The injecting of the fluid cement material500is continued for a period of time sufficient to inject an amount of the fluid cement material500into the lateral26so that the fluid cement material500completely surrounds the production tubing system304balong and fills an annular space between the outer surface of the production tubing system304band an internal surface of the wall300of the lateral26for the distance from the distal end212of the gathering section210to a position near or just beyond the packer202of the production tubing system304b. Desirably, after the well operator injects the fluid cement material500around the production tubing system304bto the packer202, the packer202is set by expanding the rubber seals276to form a seal between the packer202and the internal surface of the wall300of the lateral26, as shown by the production tubing system304aalready installed in the upper lateral24.

After the packer202has been set and a seal formed between the packer202and the wall300of the lateral26, as shown by the production tubing system304alocated in the upper lateral24, any fluid cement material500remaining in the internal passageways of the production tubing system304bmay be removed by means such as flushing, described above with respect to the single lateral production well, or by passing a swab through the production tubing system304b.

After any unwanted fluid cement material500is removed from the internal passages of the production tubing system304b, and desirably, the surrounding hydrocarbon production zone14fraced in the manner described above, the work string207is disconnected from the packer202of the production tubing system304b. The junction400and all portions of the lateral26not sealed off by the expanded packer202may be flushed by passing a fluid through the main borehole and thereby removing residual fluid cement material500from the lateral borehole26and the junction400. If multiple junctions with other laterals are present, flushing of all the junctions can be carried out simultaneously without the danger of unwanted flushing fluid being directed past the expanded packer202.

After flushing of the lateral26and junction400, the production tubing system304bcan be connected to standard production tubing and oil and gas extracted from the hydrocarbon production zone14around the lateral26in the conventional manner. In such applications, the production tubing systems304a,304bremain in place during production.

It should be noted that in the production tubing systems304a,304bembodying the present invention, the anchor204is set hydraulically prior to mechanically setting the packer202. Importantly, this sequence assures that the production tubing systems304a,304bare secured in place prior to providing a seal of the annular area to be filled with cement. If the anchor204is not set first, the production tubing system304bmay shift during injection of the fluid cement material500to a position where the packer202is exposed or even has passed above the junction400and the junction400is inadvertently filled with fluid cement material500. In addition, without setting the anchor204, there is no means by which the apparatus can resist the compressive forces that must be exerted by the well operator to later set the packer202.

The present invention is particularly useful in extracting oil and gas from hydrocarbon production zones where multilateral boreholes are used to cover a wider production zone with a single wellhead. Not only is the production increased as a result of fracing the production zone around each lateral in the manner described herein, but also by avoiding undesired contamination of a subsequently-formed lateral with a main or other lateral bores.

The present invention is described above in terms of a preferred illustrative embodiment in which a specifically described packer, anchor, and gathering tubing are described. Those skilled in the art will recognize that alternative constructions of a hydraulically actuated anchor, a mechanically actuated packer, and differently constructed gathering tubing can be used in carrying out the present invention.

Other aspects, features, and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims.