Abstract: A bottom hole assembly supports a diverter for landing in an existing multilateral junction. Once landed set down weight allows the BHA to progress through the diverter opening into a main bore, for example. A protective sleeve for the seal assembly lands on a shoulder above the targeted seal bore. Further advancing of the BHA moves the seal assembly out of the protective sleeve that has landed on the shoulder by the polished bore. Once the seals are in position in the bore a treatment can be accomplished. On picking up the seal assembly retracts into the protective sleeve and the BHA engages the diverter to bring the BHA and the diverter out of the borehole at the same time.

Abstract: An adjustable tubular string nose uses axially relatively movable wedge segments to form a variable diameter ring shape using technology described in U.S. Pat. No. 7,128,146 in another context. The nose has a seat around a passage therethrough. After insertion of the nose into a first bore, typically a main bore, the nose is retracted out of the main bore and pressure against a seated bore in the nose expands the nose radially to a degree where re-entry into the main bore is precluded but entry into a lateral bore is still possible. The string advances onto a lateral no-go. This signals surface personnel to pick up and raise pressure to blow the seated ball through the seat to again open the passage in the nose. A seal stack behind the nose in advanced into a lateral seal bore and the treatment can then commence.

Abstract: A method of treating a first bore and at least one second bore connected to the first bore in one downhole trip includes guiding a treating tool including a seal assembly defining and a shroud extending about the seal assembly downhole, guiding the seal assembly and the shroud along a diverter positioned near an intersection of the first bore and the at least one second bore into the at least one second bore, shifting the shroud relative to the seal assembly exposing the seal assembly in the at least one second bore, performing a first treatment in the at least one second bore, positioning the seal assembly and the shroud uphole of the diverter, passing the seal assembly through an opening in the diverter having a diverter opening, and performing a second treatment in the first bore.

Abstract: A method of completing a wellbore system that includes a main wellbore and a lateral wellbore intersecting the main wellbore at a junction is disclosed, wherein in one embodiment the method includes placing a first outer assembly below the junction in the main wellbore and placing a second outer assembly below the junction in the lateral wellbore; placing a first inner assembly in the second outer assembly with a top end thereof below the junction, the top end of the first inner assembly including a first wet connect associated with at least one link in the first inner assembly; and connecting a second wet connect of a string with the first wet connect with a top end of the string having a third wet connect corresponding to the at least one link above the junction in the main wellbore.

Abstract: A method of treating a first bore and at least one second bore connected to the first bore in one downhole trip includes guiding a treating tool including a seal assembly defining and a shroud extending about the seal assembly downhole, guiding the seal assembly and the shroud along a diverter positioned near an intersection of the first bore and the at least one second bore into the at least one second bore, shifting the shroud relative to the seal assembly exposing the seal assembly in the at least one second bore, performing a first treatment in the at least one second bore, positioning the seal assembly and the shroud uphole of the diverter, passing the seal assembly through an opening in the diverter having a diverter opening, and performing a second treatment in the first bore.

Abstract: An adjustable tubular string nose uses axially relatively movable wedge segments to form a variable diameter ring shape using technology described in U.S. Pat. No. 7,128,146 in another context. The nose has a seat around a passage therethrough. After insertion of the nose into a first bore, typically a main bore, the nose is retracted out of the main bore and pressure against a seated bore in the nose expands the nose radially to a degree where re-entry into the main bore is precluded but entry into a lateral bore is still possible. The string advances onto a lateral no-go. This signals surface personnel to pick up and raise pressure to blow the seated ball through the seat to again open the passage in the nose. A seal stack behind the nose in advanced into a lateral seal bore and the treatment can then commence.

Abstract: A bottom hole assembly supports a diverter for landing in an existing multilateral junction. Once landed set down weight allows the BHA to progress through the diverter opening into a main bore, for example. A protective sleeve for the seal assembly lands on a shoulder above the targeted seal bore. Further advancing of the BHA moves the seal assembly out of the protective sleeve that has landed on the shoulder by the polished bore. Once the seals are in position in the bore a treatment can be accomplished. On picking up the seal assembly retracts into the protective sleeve and the BHA engages the diverter to bring the BHA and the diverter out of the borehole at the same time.

Abstract: A method of completing a wellbore system that includes a main wellbore and a lateral wellbore intersecting the main wellbore at a junction is disclosed, wherein in one embodiment the method includes placing a first outer assembly below the junction in the main wellbore and placing a second outer assembly below the junction in the lateral wellbore; placing a first inner assembly in the second outer assembly with a top end thereof below the junction, the top end of the first inner assembly including a first wet connect associated with at least one link in the first inner assembly; and connecting a second wet connect of a string with the first wet connect with a top end of the string having a third wet connect corresponding to the at least one link above the junction in the main wellbore.

Abstract: A hydrocarbon production assembly within a multilateral wellbore, the multilateral wellbore having a main bore portion which extends downwardly from surface and a lateral leg which extends radially away from the main bore portion.

Abstract: A diverting system includes, a first tubular, a second tubular receptive to the first tubular having at least one lateral extending therefrom, the first tubular is runnable into the second tubular as well as into the at least one lateral, an engaging device in operable communication with both the first tubular and the second tubular, and a diverting tool in operable communication with the engaging device configured to selectively divert the first tubular into the at least one lateral.

Abstract: A lateral junction for a multilateral wellbore having a main bore and a lateral leg which extends away from the main bore. The lateral junction includes a seal bore diverter and a hanger that is insertable into the seal bore diverter to form the junction. An engagement mechanism interlocks the hanger and seal bore diverter together at the crux of their joining.

Abstract: In one aspect, a wellbore system is disclosed that in one non-limiting embodiment includes a first wellbore capable of producing a fluid from a first formation, a second wellbore intersecting the first wellbore at a junction, wherein the second wellbore is an open hole and capable of producing a fluid from a second formation and a sand screen at the junction configured to inhibit particles larger than a selected size from flowing from the second wellbore and the junction into the first wellbore.

Abstract: A multilateral junction system includes a multilateral junction device including a first bore leg; a second bore leg; a joint section having a first opening connected to the first bore leg and a second opening connected to the second bore leg. A main body extending from the joint section and including a third opening; and, a tube connected to the third opening. The tube configured to enable an upper completion to be run into a borehole together with the multilateral junction device. Also included is a method of improving multilateral operations in a borehole.

Abstract: In one aspect, a wellbore system is disclosed that in one non-limiting embodiment includes a first wellbore capable of producing a fluid from a first formation, a second wellbore intersecting the first wellbore at a junction, wherein the second wellbore is an open hole and capable of producing a fluid from a second formation and a sand screen at the junction configured to inhibit particles larger than a selected size from flowing from the second wellbore and the junction into the first wellbore.

Abstract: A multilateral junction system includes a multilateral junction device including a first bore leg; a second bore leg; a joint section having a first opening connected to the first bore leg and a second opening connected to the second bore leg. A main body extending from the joint section and including a third opening; and, a tube connected to the third opening. The tube configured to enable an upper completion to be run into a borehole together with the multilateral junction device. Also included is a method of improving multilateral operations in a borehole.

Abstract: A diverting system includes, a first tubular, a second tubular receptive to the first tubular having at least one lateral extending therefrom, the first tubular is runnable into the second tubular as well as into the at least one lateral, an engaging device in operable communication with both the first tubular and the second tubular, and a diverting tool in operable communication with the engaging device configured to selectively divert the first tubular into the at least one lateral.

Abstract: A method of running a first tubular within a second tubular includes running the first tubular into the second tubular past at least one lateral extending from the second tubular, running a diverting tool at the first tubular with the running of the first tubular, withdrawing the first tubular from the second tubular until an end of the first tubular is beyond a junction between the at least one lateral and the second tubular and, running the first tubular into the at least one lateral.

Abstract: An engaging device includes a body selectively slidably engagable about a first tubular runnable within a second tubular. The body is runnable past at least one profile on the second tubular in a first direction during a first running and is prevented from running past the at least one profile on subsequent runs subsequent to running by the at least one profile in a second direction.

Abstract: A method of running a first tubular within a second tubular includes running the first tubular into the second tubular past at least one lateral extending from the second tubular, running a diverting tool at the first tubular with the running of the first tubular, withdrawing the first tubular from the second tubular until an end of the first tubular is beyond a junction between the at least one lateral and the second tubular and, running the first tubular into the at least one lateral.

Abstract: An engaging device includes a body selectively slidably engagable about a first tubular runnable within a second tubular. The body is runnable past at least one profile on the second tubular in a first direction during a first running and is prevented from running past the at least one profile on subsequent runs subsequent to running by the at least one profile in a second direction.