drilling additional wellbores from that same well For example, the fluid recovery rate and the well's economic life can be increased by drilling a horizontal interval from a main wellbore radially outward into one or more formations Still further increases in recovery and well life can be attained by drilling multiple horizontal intervals into multiple formations Once the multilateral wellbores have been drilled and completed

there is a need for the recovery of fluids from each wellbore to be individually controlled Currently, the control of the fluid recovery from these multilateral wellbores has been limited in that once a lateral wellboie has been opened it is not possible to

selectively close off and/or reopen the lateral wellbores without the need for the use of additional equipment, such as wiieiine units, coiled tubing units and workover rigs

The need for selective fluid recoveiy is important in that individual producing intervals usually contain hydrocarbons that have diffeient physical and chemical

properties and as such may have different unit values Co-mingling a valuable and desirable crude with one that has, for instance, a high sulphur content would not be

commercially expedient, and in some cases is prohibited by governmental regulatory

authorities Also, because different intervals inherently contain differing volumes of

hydrocarbons, it is highly probable that one interval will deplete before the others, and

will need to be easily and inexpensively closed off fiom the veitical wellbore before the other intervals

The use of workover rigs, coiled tubing units and wireline units are relatively inexpensive if used onshore and in typical oilfield locations, however, mobilizing these resources for a remote offshore well can be very expensive in terms of actual dollars spent, and in terms of lost production while the resources are being moved on site In the case of subsea wells (where no surface platform is piesent), a drill ship or workover vessel mobilization would be required to meiely open/close a downhole wellbore valve

The following patents disclose the current multilateral drilling and completion techniques. U.S. Patent 4,402,551 details a simple completion method when a lateral wellbore is drilled and completed through a bottom of an existing traditional, vertical wellbore Control of production fluids from a well completed in this manner is by traditional surface wellhead valving methods, since improved methods of recovery from only one lateral and one interval is disclosed The importance of this patent is the recognition of the role of orienting and casing the lateral wellbore, and the care taken in sealing the juncture where the vertical borehole interfaces with the lateral wellbore. U.S. Patent 5,388,648 discloses a method and apparatus for sealing the juncture

between one or more horizontal wells using deformable sealing means This completion method deals primarily with completion techniques prior to insertion of production

tubing in the well While it does address the penetration of multiple intervals at different

depths in the well, it does not offer solutions as to how these different intervals may be

selectively produced.

U.S. Patent 5,337,808 discloses a technique and apparatus for selective multi-

zone vertical and/or horizontal completions This patent illustrates the need to

selectively open and close individual intervals in wells where multiple intervals exist, and discloses devices that isolate these individual zones through the use of workover rigs

U.S. Patent 5,447,201 discloses a well completion system with selective remote surface control of individual producing zones to solve some of the above described problems. Similarly, U.S. Patent 5,41 1,085, commonly assigned hereto, discloses a production completion system which can be remotely manipulated by a controlling

means extending between downhole components and a panel located at the surface. Each of these patents, while able to solve recovery problems without a workover rig, fails to address the unique problems associated with multilateral wells, and teaches only recovery methods from multiple interval wells Λ multi-lateral well that requires reentry remediation which was completed with either of these techniques has the same problems as before: the production tubing would have to be removed, at great expense, to re-enter the lateral for remediation, and reinserted in the well to resume production

U.S. Patent 5,474, 131 discloses a method for completing multi-lateral wells and maintaining selective re-entry into the lateral wellbores This method allows for re-entry remediation into horizontal laterals, but does not address the need to remotely manipulate downliole completion accessories from the surface without some intervention

technique. In this patent, a special shifting tool is required to be inserted in the well on

coiled tubing to engage a set of ears to shift a flapper valve to enable selective entry to either a main wellbore or a lateral. To accomplish this, the well production must be

halted, a coiled tubing company called to the jobs site, a surface valving system attached

to the wellhead must be removed, a blow out preventer must be attached to the

wellhead, a coiled tubing injector head must be attached to the blow out preventer, and

the special shifting tool must be attached to the coiled tubing; all before the coiled tubing

can be inserted in the well

There is a need for a system to allow an operator standing at a remote control

panel to selectively permit and prohibit flow from multiple lateral well branches drilled from a common central wellbore without having to resort to common intervention techniques. Alternately, there is a need for an operator to selectively open and close a valve to implement re-entry into a lateral branch drilled from the common wellbore. There is a need for redundant power sources to assure operation of these automated

downhole devices, should one or more power sources fail. Finally, there is a need for fail safe mechanical recovery tools, should these automated systems become inoperative. The present invention has been contemplated to overcome the foregoing deficiencies and meet the above described needs. Specifically, the present invention is a system to recover fluids from a well that has either multiple intervals adjacent to a central wellbore or has multiple lateral wellbores which have been drilled from a central wellbore into a plurality of intervals in proximity to the central wellbore. In accordance with the present invention an improved method is disclosed to allow selective recovery from any of a well's intervals by remote control from a panel located at the earth's surface. This selective recovery is enabled by any number of well known controlling means, i.e. by electrical signal, by hydraulic signal, by fiber optic signal, or any combination thereof, such combination comprising a piloted signal of one of these

controlling means to operate another. Selective control of producing formations would preclude the necessity of expensive, but commonly practised workover techniques to change producing zones, such as: (1) standard tubing conveyed intervention, should a production tubing string need to be removed or deployed in the well, or (2) should a

work string need to be utilized for remediation, and would also reduce the need and

frequency of either (3) coiled tubing remediation or (4) wireline procedures to enact a

workover, as well.

Preferably, these controlling means may be independent and redundant, to assure operation of the production system in the event of primary control failure; and may be operated mechanically by the aforementioned commonly practised workover techniques to change producing zones, should the need arise. In a preferred embodiment, a well comprising a central casing adjacent at least two hydrocarbon producing formations is cemented in the earth A production tubing string located inside the casing is fixed by any of several well known completion accessories. Packers, which are well known to those skilled in the art, straddle each of the producing formations and seal an annulus, thereby preventing the produced wellbore fluids from flowing to the surface in the annulus. Λ surface activated flow control valve with an annularly openable orifice, located between the packers, may be opened or closed upon receipt of a signal transmitted from the control panel, with each producing formation, between a wellhead at the surface and the lowermost producing formation, having a corresponding flow control valve. With such an arrangement, any formation can be produced by opening its corresponding flow control valve and closing all other

flow control valves in the wellbore. Thereafter, co-mingled flow from individual

formations is prevented, or allowed, as is desired by the operations personnel at the surface control panel. Further, the size of the annularly openable orifice can be adjusted

from the surface control panel such that the rate of flow of hydrocarbons therefrom can

be adjusted as operating conditions warrant.

Should conditions in one or more of the laterals warrant re-entry by either coiled

tubing or other well known methods, a rotating lateral access door directly adjacent to

and oriented toward each lateral in the well can be selectively opened, upon receipt of a signal from the control panel above. The access door, in the open position, directs

service tools inserted into the central wellboie into the selected lateral. Closure of the access door, prevents entry of service tools running in the central wellbore from entering laterals that were not selected for remediation

In accordance with this preferred embodiment, should either the flow control valve or the rotating lateral access door lose communication with the surface control panel, or should either device become otherwise inoperable by remote control, mechanical manipulation devices that may be deployed by coiled tubing are within the scope of this invention and are disclosed herein.

The features and advantages of the piesent invention will be appreciated and

understood by those skilled in the art from the following detailed description and

drawings., in which:

Figure 1 is a schematic representation of a wellbore completed using one

preferred embodiment of the present invention.

Figures 2 A-G taken together form a longitudinal section of one preferred embodiment of an apparatus of the present invention with a lateral access door in the open position

Figures 3 A-H taken together form a longitudinal section of the apparatus of

Figure 2 with a work string shown entering a lateral, and a longitudinal section of a

selective orienting deflector tool located in position Figures 4 A-B illustrate two cross sections of Figure 3 taken along line "A-A",

without the service tools as shown therein. Figure 4-A depicts the cross section with a

rotating lateral access door shown in the open position, while Figure 4-B depicts the

cross section with the rotating lateral access door shown in the closed position.

Figure 5 illustrates a cross sections of Figure 3 taken along line "B-B", without

the service tools as shown therein.

Figure 6 illustrates a cross section of Figure 3 taken along line "D-D", and depicts a locating, orienting and locking mechanism for anchoring the multilateral flow control system to the casing. Figure 7 illustrates a longitudinal section of Figure 5 taken along line "C-C", and depicts an opening of the rotating lateral access door shown in the open position, and the sealing mechanism thereof

Figure 8 illustrates a cross section of Figure 3 taken along line "E-E", and depicts an orienting and locking mechanism for a selective orienting deflector tool and is located therein.

The present invention is a system for remotely controlling multilateral wells, and will be described in conjunction with its use in a well with three producing formations for purposes of illustration only. One skilled in the art will appreciate many differing applications of the described apparatus. It should be understood that the described invention may be used in multiples for any well with a plurality of producing formations

where either multiple lateral branches of a well are present, or multiple producing formations that are conventionally completed, such as by well perforations or uncased open hole, or by any combination of these methods. Specifically, the apparatus of the present invention includes enabling devices for automated remote control and access of

multiple formations in a central wellbore during production, and allow work and time saving intervention techniques when remediation becomes necessary.

For the purposes of this discussion, the terms "upper" and "lower", "up hole" and

"downliole", and "upwardly" and downwardly" are relative terms to indicate position and

direction of movement in easily recognized terms. Usually, these terms are relative to

a line drawn from an upmost position at the surface to a point at the center of the earth,

and would be appropriate for use in relatively straight, vertical wellbores. However, when the wellbore is highly deviated, such as from about 60 degrees from vertical, or horizontal these terms do not make sense and therefore should not be taken as limitations. These terms are only used for ease of understanding as an indication of what the position or movement would be if taken within a vertical wellbore.

Referring now to Figure 1 , a substantially vertical wellbore 10 is shown with an upper lateral wellbore 12 and a lower lateral wellbore 14 drilled to intersect an upper producing zone 16 and an intermediate producing zone 18, as is well known to those skilled in the art of multilateral drilling. A production tubing 20 is suspended inside the vertical wellbore 10 for recovery of fluids to the earth's surface. Adjacent to an upper lateral well junction 22 is an upper fluid flow control apparatus 24 of the present

invention while a lower fluid flow control apparatus 26 of the present invention is

located adjacent to a lower lateral well junction 28. Each fluid flow control apparatus 24 and 26 are the same as or similar in configuration. In one preferred embodiment, the fluid flow control apparatus 24 and 26 generally comprises a generally cylindrical mandrel body having a central longitudinal bore extending therethrough, with threads

or other connection devices on one end thereof for interconnection to the production

tubing 20. A selectively operable lateral access door is provided in the mandrel body for

alternately permitting and preventing a service tool from laterally exiting the body

therethrough and into a lateral wellbore. In addition, in one preferred embodiment, a

selectively operable flow control valve is provided in the body for regulating fluid flow

between the outside of the body and the central bore.

In the fluid flow control apparatus 24 a lateral access door 30 comprises an

opening in the body and a door or plug member. The door may be moved longitudinally or radially, and may be moved by one or more means, as will be described in more detail

below. In Figure 1 the door 30 is shown oriented toward its respective adjacent lateral wellbore. A pair of permanent or retrievable elastomeric packers 32 are provided on separate bodies that are connected by thieads to the mandrel body or, preferably, are connected as part of the mandrel body. The packers 32 are used to isolate fluid flow between producing zones 16 and 18 and provide a fluidic seal thereby preventing co- mingling flow of produced fluids through a wellbore annulus 34. A lowermost packer 36 is provided to anchor the production tubing 20, and lo isolate a lower most producing zone (not shown) from the producing zones 16 and 18 above. A

communication conduit or cable or conduit 38 is shown extending from the fluid flow control apparatus 26, passing through the isolation packers 32, up to a surface control panel 40. A tubing plug 42, which is well known, may be used to block flow from the lower most producing zone (not shown) into the tubing 20.

A well with any multiple of producing zones can be completed in this fashion, and a large number of flow configurations can be attained with the apparatus of the present invention. For the purposes of discussion, all these possibilities will not be

discussed, but remain within the scope of the present invention. In the configuration

shown in Figure 1, the production tubing 20 is plugged at the lower end by the tubing plug 42, the lower fluid flow control apparatus 26 has a flow control valve is shown

closed, and the upper fluid flow control apparatus 24 is shown with its flow control

valve in the open position. This production configuration is managed by an operator

standing on the surface at the control panel 40, and can be changed therewith by manipulation of the controls on that panel. In this production configuration, flow from

ail producing formations is blocked, except from the upper producing zone 16. Hydrocarbons 44 present therein will flow from the formation 16, through the upper lateral wellbore 12, into the annulus 34 of the vertical wellbore 10, into a set of ports 46 in the mandrel body and into the interior of the production tubing 20. From there, the

produced hydrocarbons move to the surface.

Turning now to Figures 2 A-G, which, when taken together illustrate the fluid flow control apparatus 24. An upper connector 48 is provided on a generally cylindrical mandrel body 50 for sealable engagement with the production tubing 20. An elastomeric packing element 52 and a gripping device 54 are connected to the mandrel body 50. A first communication conduit 56, preferably, but not limited to electrical communication, and a second communication conduit 58, preferably, but not limited to hydraulic control communication, extend from the earth's surface into the mandrel 50. The first 56 and

second 58 communication conduits communicate their respective signals to/from the earth's surface and into the mandrel 50 around a set of bearings 60 to a slip joint 62. The electrical communication conduit or cable 56 connects at this location, while the hydraulic communication conduit 58 extends therepast. The bearings 60 reside in a rotating swivel joint 64, which allows the mandrel body 50 and its lateral access door 30 to be rotated relative tubing 20, to ensure that the lateral access door 30 is properly

aligned with the lateral wellbore. Further, the electrical communication conduit or cable

56 communicates with a first pressure transducer 66 to monitor annulus pressure, a

temperature and pressure sensor 68 to monitor temperature and hydraulic pressure,

and/or a second pressure transducer 70 to monitor tubing pressure. Signals from these

transducers are communicated to the control panel 40 on the surface so operations

personnel can make informed decisions about downhole conditions.

In this preferred embodiment, the electrical communication conduit or cable also communicates with a solenoid valve 72, which selectively controls the flow of hydraulic

fluid from the hydraulic communication conduit 58 to an upper hydraulic chamber 74, across a movable piston 76, to a lower hydraulic chamber 78. The differential pressures in these two chambers 74 and 78 move the operating piston 76 a sleeve extending therefrom in relation to an annularly openable port or orifice 80 in the mandrel body 50 to allow hydrocarbons to flow from the annulus 34 to the tubing 20. Further, the rate of fluid flow can be controlled by adjusting the relative position of the piston 76 through the use of a flow control position indicator 82, which provides the operator constant and instantaneous feedback as to the size of the opening selected

In some instances, however, normal operation of the flow control valve may not be possible for any number of reasons. An alternate and redundant method of opening or closing the flow control valve and the annularly operable orifice 80 uses a coiled tubing deployed shifting tool 84 landed in a profile in the internal surface of the mandrel

body 50. Pressure applied to this shifting tool 84 is sufficient to move the flow control valve to either the open or closed positions as dictated by operational necessity, as can

be understood by those skilled in the art.

The electrical communication conduit or cable 58 further communicates electrical

power to an high torque rotary motor 88 which rotates a pinion gear 90 to rotate a lateral access plug member or door 92. This rotational force opens and closes the

rotating lateral access door 92 should entry into the lateral wellbore be required. In some

instances, however, nonnal operation rotating lateral access door 92 may not be possible

for any number of reasons. An alternate, and redundant method of opening the rotating

lateral access door 92 is also provided wherein a coiled tubing deployed rotary tool 94

is shown located in a lower profile 96 in the interior of the mandrel body 50. Pressure applied to this rotary tool 94 is sufficient to rotate the rotating lateral access door 92 to

either the open or closed positions as dictated by operational necessity, as would be well known to those skilled in the art.

When the fluid flow apparatus 24 and 26 are set within the wellbore the depth and azimuthal orientation is controlled by a spring loaded, selective orienting key 98 on the mandrel body 50 which interacts with an orienting sleeve within a casing nipple, which is well known to those skilled in the art. Isolation of the producing zone is assured by the second packing element 52, and the gripping device 54, both mounted on the mandrel body 50, where an integrally formed lower connector 100 for sealable engagement with the production tubing 20 resides.

Referring now to Figures 3 A-H, which, when taken together illustrate the upper fluid flow control apparatus 24, set and operating in a well casing 102. In this embodiment, an upper valve seat 104 on the mandrel 50 and a lower 106 valve seat on the piston 76 are shown sealably engaged, thereby blocking fluid flow. The lateral access door 92 is in the form of a plug member that is formed at an angle to facilitate movement of service tools into and out of the lateral. Once so opened, a coiled tubing

108, or other well known remediation tool, can be easily inserted in the lateral wellbore.

For purposes of illustration, a flexible tubing member 1 10 is shown attached to the

coiled tubing 108, which is in turn, attached to a pulling tool 1 12, that is being inserted

in a cased lateral 1 14.

A selective orienting deflector tool 1 16 is shown set in a profile 1 18 formed in

the interior surface of the upper fluid flow control apparatus 24. The deflector tool 1 16

is located, oriented, and held in position by a set of locking keys 120, which serves to

direct any particular service tool inserted in the vertical wellbore 10, into the proper cased lateral 1 14.

The depth and azimuthal orientation of the assembly as hereinabove discussed is controlled by a spring loaded, selective orienting key 98, which sets in a casing profile 122 of a casing nipple 124. Isolation of the producing zone is assured by the second packing element 52, and the gripping device 54, both mounted on the central mandrel

50.

Figure 4 A-B is a cross section taken al "A-A" of Figure 3-D and represents a view of the top of the rotating lateral access door 92 Figure 4-A illustrates the relationship of the well casing 102, the cased lateral 1 14, the pinion gear 90, and the rotating lateral access door 92, shown in the open position. Figure 4-B illustrates the relationship of the well casing 102, the cased lateral 1 14, the pinion gear 90, and the rotating lateral access door 92, shown in the closed position. Referring now to Figure 5, which is a cross section taken at "B-B" of Figure 3-E, and is shown without the

flexible tubing member 110 in place, at a location at the center of the intersection of the

cased lateral 1 14, and the well casing 102 This diagram shows the rotating lateral

access door 92 in the open position, and a door seal 126. Figure 6 is a cross section

taken at "D-D" of Figure 3-F and illustrates in cross section the manner in which the

selective orienting key 98 engages the casing nipple 124 assuring the assembly described herein is located and oriented at the correct position in the well.

Turning now to Figure 7, which is a longitudinal section taken at "C-C" of

Figure 5. This diagram primarily depicts the manner in which the door seal 126 seals

around an elliptical opening 128 formed by the intersection of the cylinders formed by

the cased lateral 1 14 and the rotating lateral access door 92. This view clearly shows

the bevel used to ease movement of service tools into and out of the cased lateial 1 14. The final diagram, Figure 8, is a cross section tnken at "E-E" orFiguie 3-E. This shows the relationship of the casing nipple 124, the orienting deflector tool 1 16, the profile 1 18 formed in the interior surface of the uppet fluid flow control apparatus 24, and how the locking keys 120 interact with the profile 1 18.

In a typical operation, the oil well pioduction system of the piesent invention is utilized in wells with a plurality of pioducing foi mations which may be selectively produced. Referring once again to Figuie I , if il weie opeialioimlly desiiable to produce from the uppet pioducing zone 16 without co-iniπgling the flow with the hydiocaibons from the other formations; first a tubing plug 42 would need to be set in the tubing to isolate the lower producing zone (not shown). The opeialor standing al Ihe control panel would then configure the conliol panel 40 to close the lower fluid flow control apparatus 26, and open the upper fluid flow conliol appaiatus 24. Both totaling lateral access doois 30 would be configured closed. In this configuiation, flow is blocked from

bolh the intermediate producing zone 18, and the lower pioducing zone and hydrocarbons from the upper producing zone would enter the upper lateial 12, flow into the annulus 34, through the set of porls 46 on (he upper fluid flow control apparatus 24, and into the production tubing 20, which then moves lo the surface. Different flow regimes can be accomplished simply by altering Ihe anangement of the open and closed valves from the control panel, and moving the location of the tubing plug 42. The

necessity of the tubing plug 42 can be eliminated by utilizing another flow control valve to meter flow from the lower foi mation as well.

When operational necessity dictates that one or moie of the laterals requires re¬

entry, a simple operation is all that is necessaiy to gain access therein. For example,

assume the upper lateral 12 is chosen foi remediation T he operator at the remote

control panel 40 shuts all flow control valves, assuies that nil rotating laleial access doors 30 are closed except the one adjacent the upper lateial 12, which would be opened. If the orienting deflector tool 1 16 is nol installed, it would become necessary to install it at this time by any of seveial well known methods. In all piobabilily, however, the deflector tool 1 16 would already be in place. Enlry of the service tool in the lateral could then be accomplished, piefeinbly by coiled tubing or n flexible lubing such as CO-FLEX1P brand pipe, because the pioduction tubing 20 now has an opening oriented towaid the lateral, and a tool is piesent lo deflect tools i mining in the tubing into the desired lateral. Production may be easily resumed by configuring the flow conliol valves as before.

Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be undei stood lliat other and further modifications, apart from those shown or suggested herein, may be made wilhin the scope of the present invention as defined in Ihe appended claims