Abstract: A sliding sleeve valve for wellbore operations includes: a tubular body including a tubular wall including an outer surface and an inner surface defining an inner bore; a fluid port extending through the tubular wall and providing fluidic communication between the outer surface and the inner bore; a sliding sleeve in the inner bore slidably moveable between a port closed position and a port open position, the sliding sleeve including a ball seat on which a plug is landed to move the sleeve from the port closed position to the port open position; an initial sleeve holding mechanism for holding the sliding sleeve in the port closed position, the initial sleeve holding mechanism selected to be overcome by landing a plug on the ball seat to move the sliding sleeve; and a second sleeve holding mechanism for holding the sliding sleeve in the port closed position after the sliding sleeve is reclosed from the port open position to the port closed position, the second sleeve holding mechanism selected to be overcome b

Abstract: A fluid treatment method includes positioning a tubing string in a non-vertical borehole section, and applying a sliding-sleeve-actuating fluid pressure within the tubing string's inner bore such that a first sliding sleeve moves from a position in which a first port is covered to another position in which the first port is exposed to the inner bore. The method further includes pumping fluid through the first port. The method also includes conveying first and second fluid conveyed sealing devices through the inner bore such that the first and second fluid conveyed sealing device seal against the seats of second and third sliding sleeves, respectively, thereby moving the second and third sliding sleeves to open port positions exposing second and third ports, respectively. The method also includes pumping fluid through the second and third ports to treat first and second portions of the formation, respectively.

Abstract: A method for fracturing a formation includes positioning a fluid treatment string in the formation. The fluid treatment string includes a port configured to pass fracturing fluid from within the string's inner bore to outside the string, and a sliding sleeve located inside string and configured to move by fluid pressure within the inner bore of the fluid treatment string between (i) a first position in which the sliding sleeve covers the port and (ii) a second position in which the sliding sleeve exposes the port to the inner bore. The method also includes applying a fluid pressure within the inner bore such that the sliding sleeve moves from the first position to the second position without the sliding sleeve engaging a sealing device, and pumping fracturing fluid through the inner bore and through the port to fracture a portion of the formation.

Abstract: A tubing string external structure forms a pathway in a cemented annulus that extends from a fluid treatment port axially away from the port and along a length of the tubing string. Wellbore treatment fluids can be injected through the tubing string and through the pathway to contact the wellbore wall along a length greater than the axial length of the port.

Abstract: A wellbore treatment apparatus includes: a tubing string including a wall defining an inner diameter and a port extending through the wall, the port closed by a closure including a plug-actuated sliding sleeve; and a port opening apparatus including a wireline deployable through the inner diameter of the tubing string to extend to a position adjacent the plug-actuated sliding sleeve and an actuator plug carried on and axially slideable along the wireline, the actuator plug sized to land in the plug-actuated sliding sleeve to actuate the plug-actuated sliding sleeve, while remaining on the wireline. The apparatus can be employed in a method by running the tubing string into a well, placing the slickline in the string and running the actuator plug along the wireline to land on and actuate a sleeve in the string.

Abstract: A method and apparatus for wellbore control include a downhole facing ball stop and sealing area that can stop and seal with an actuator ball migrating toward surface with wellbore returns or production. The downhole facing ball stop operates with the returning actuator ball to create a seal against any returns or production migrating toward surface such that well control is provided until the ball is removed from the sealing area or a bypass is opened around the seal.

Abstract: A method for wellbore treatment includes running a liner into a wellbore, the liner including a wall, an inner bore defined by the wall, a first port through the wall, a second port though the wall spaced axially from the first port, a first removable closure for the first port and a second removable closure for the second port; positioning the liner in an open hole section of the wellbore to create an annulus between the liner and a portion of the wellbore wall and with the second port downhole of the first port; inserting a treatment string assembly into the liner, the treatment string assembly including a tubing string and an annular seal about the tubing string and being insertable into the inner bore of the liner; setting the annular seal to create a seal between the tubing string and the liner downhole of the second port; and while the first port is closed to fluid flow therethrough, pumping wellbore treatment fluid into an annular area between the tubing string and the liner such that the fluid passes

Abstract: A tubing string assembly is disclosed for fluid treatment of a wellbore. The tubing string can be used for staged wellbore fluid treatment where a selected segment of the wellbore is treated, while other segments are sealed off. The tubing string can also be used where a ported tubing string is required to be run in in a pressure tight condition and later is needed to be in an open-port condition.

Abstract: To address concerns of kobe plug cap portions being inadvertently removed, for example, by abutment with strings or tools passing thereby, a shielding structure may be employed to protect the cap against inadvertent removal. The port opening tool useful with the kobe plug is selected to overcome the shielding structure to open the kobe plug. To address concerns of a portion of the kobe plug becoming loose in the tubing string inner bore, a capturing mechanism may be provided that captures the cap portion after it is removed to open the kobe plug and prevented the cap portion from becoming loose in the inner bore of the tubing string.

Abstract: A method for isolating a perforated interval of a well, the well including a casing liner having a wall with a plurality of perforations therethrough forming the perforated interval, the method comprising: providing a tool including a tubular body including an inner diameter and an outer surface, a first open end and a second open end, the first and second open ends providing access to the inner diameter; and a sealing element to isolate a mid region of the outer surface from the first open end and the second open end; positioning the tool in the well with the tubular first open end adjacent and above an uppermost perforation of the perforated interval and the second open end adjacent and below a lowermost perforation of the perforated interval; and installing the tool in the well with the sealing element sealing between the tubular body and the casing wall above the uppermost perforation of the perforated interval and below the lowermost perforation of the perforated interval to isolate fluid flow between th

Abstract: A method for fracturing a hydrocarbon-containing formation includes running a tubing string into an open hole and uncased, non-vertical section of the wellbore, and expanding first, second, and third solid body packers until each sets and seals against the wellbore wall. The method also includes applying a first pressure within the tubing string inner bore such that the hydraulically actuated sliding sleeve moves from a closed port position to an open port position without engaging any fluid conveyed sealing device. The method also includes conveying a sealing device through the tubing string, passing through a first sliding sleeve and landing in and sealing against a second sliding sleeve's seat moving the second sliding sleeve to an open port position permitting fluid flow through a second port. And the method includes pumping fracturing fluid through the second port and into an annular wellbore segment to fracture the hydrocarbon-containing formation.

Abstract: A method and apparatus for wellbore control include a downhole facing ball stop and sealing area that can stop and seal with an actuator ball migrating toward surface with wellbore returns or production. The downhole facing ball stop operates with the returning actuator ball to create a seal against any returns or production migrating toward surface such that well control is provided until the ball is removed from the sealing area or a bypass is opened around the seal.

Abstract: A wellbore fluid treatment assembly includes: a tubing string, a fluid port extending through the tubing string wall, the fluid port positioned in a shift gap created by movement of a sliding sleeve valve when opening the fluid port; and a tool for locating the fluid port in the tubing string, the tool including: a body, a locking protrusion encircling a circumference of the body, at least a portion of the locking protrusion having a length measured along the tool's long axis selected to fit into the shift gap.

Abstract: A back-up ring assembly for a wellbore packer that acts as an extrusion limiter for a packing element and engages the wellbore bore, also operating as a slip to anchor the packer in place. A wellbore packer includes a single structure that acts both to back up the extrusion of the packing element and to engage the wellbore wall. For example, the structure is a back-up ring that includes a gripping structure on its outer wall-contacting surface.

Abstract: A tubing string assembly for fluid treatment of a wellbore includes substantially pressure holding closures spaced along the tubing string, which each close at least one port through the tubing string wall. The closures are openable by a sleeve drivable through the tubing string inner bore.

Abstract: A method for fracturing a hydrocarbon-containing formation includes running a tubing string into an open hole and uncased, non-vertical section of the wellbore, and expanding first, second, and third solid body packers until each sets and seals against the wellbore wall. The method also includes applying a first pressure within the tubing string inner bore such that the hydraulically actuated sliding sleeve moves from a closed port position to an open port position without engaging any fluid conveyed sealing device. The method also includes conveying a sealing device through the tubing string, passing through a first sliding sleeve and landing in and sealing against a second sliding sleeve's seat moving the second sliding sleeve to an open port position permitting fluid flow through a second port. And the method includes pumping fracturing fluid through the second port and into an annular wellbore segment to fracture the hydrocarbon-containing formation.

Abstract: A back-up ring assembly for a wellbore packer that acts as an extrusion limiter for a packing element and engages the wellbore bore, also operating as a slip to anchor the packer in place. A wellbore packer includes a back-up ring that includes a gripping structure on its outer wall-contacting surface that acts both to back up the extrusion of the packing element and to engage the wellbore wall.

Abstract: A method for fluid treatment of a borehole including a main wellbore, a first wellbore leg extending from the main wellbore and a second wellbore leg extending from the main wellbore, the method includes: running a wellbore tubing string apparatus into the first wellbore leg; conveying a plug into the wellbore tubing string apparatus to actuate a plug-actuated sleeve in the wellbore tubing string apparatus to open a port through the wall of the wellbore tubing string apparatus covered by the sleeve; employing a plug retainer to retain the plug in the tubing string against passing outwardly from the tubing string apparatus; allowing fluids to flow toward surface outwardly from the tubing string apparatus; and performing operations in the second wellbore leg.

Abstract: A stage tool for cementing a wellbore annulus, comprising: a main body including a tubular wall with an outer surface and an inner bore extending from a top end to a bottom end; a cementing port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; a valve for controlling flow through the cementing port between the outer surface and the inner bore; and a plug sealing a circulation path between the valve and the outer surface, the plug being expellable by pressure applied from the inner bore. The stage tool may be run in with the plug isolating annular pressure from the valve. After sufficient cement has been introduced to the annulus, the stage tool fluid port can be closed to hold the cement in the annulus.

Abstract: A stage tool for wellbore annular cementing may be opened for cementing by hydraulic actuation of a sliding sleeve valve from over a fluid port. After sufficient cement has been introduced, the stage tool fluid port can be closed by compressing two telescopically arranged parts of its tubular body to further overlap each other and overlie the fluid port. This permits the stage tool to be closed without employing a plug.