A wellbore lining system that puts liners into place immediately behind the drill head tool is used in drilling and for preparing natural gas hydrate (NGH) deposits for production of its natural gas. The system overcomes the requirement of setting casing from the wellhead, which controls well bore diameter with depth and allows for flexibility in well bore size at any depth. Wellbore liners stabilize the well walls by being very tightly fitting against bounding rocks and sediments, which overcomes the requirement for cementing, which commonly accompanies conventional well casing. In addition, liners can be emplaced with designed impermeability, permeability, and complex flow-through patterns so that production processes, such as sand flow, can be put in place as part of a liner section.

The flow control device comprises one or more stacked spiral paths where the shape of an inlet to an end of a spiral has a taper on one or more sides to gradually increase the polymer velocity to eliminate rapid acceleration points as the flow enters the spiral path. The entrance with its taper can be curved to get into the spiral. The spiral can be entered tangentially or radially or axially.

The flow control device comprises one or more stacked spiral paths where the shape of an inlet to an end of a spiral has a taper on one or more sides to gradually increase the polymer velocity to eliminate rapid acceleration points as the flow enters the spiral path. The entrance with its taper can be curved to get into the spiral. The spiral can be entered tangentially or radially or axially.

A flow balancing device facilitates polymer injection in a horizontal formation in a manner that minimizes shear effects on the injected polymer. Features of the device reduce velocity using a broad circumferentially oriented inlet plenum that leads to a circumferentially oriented path having zig-zag fluid movement characterized by broad passages that define the zig-zag pattern so as to reduce velocity at such transition locations. Because the path is circumferentially oriented there is room for broad transition passages independent of the housing diameter. The broad crescent shaped inlet plenum also reduces inlet velocity, and therefore shear, to preserve the viscosity of the injected polymer. Other materials can be injected or the device can be employed in production service as well as injection. A related method employs the described device for injection.

Coating compositions for coating fluid handling components, and related methods, may include in some aspects a coating composition having a trifunctional silane, a silanol, and a filler. The coating composition may be applied to a surface of a fluid handling component that is configured to be exposed to a fluid. The coating composition may be applied to at least partially cover or coat the surface. The coating composition may be configured to chemically bond with a cured primer composition that includes an epoxy.

Coating compositions for coating fluid handling components, and related methods, may include in some aspects a coating composition having a trifunctional silane, a silanol, and a filler. The coating composition may be applied to a surface of a fluid handling component that is configured to be exposed to a fluid. The coating composition may be applied to at least partially cover or coat the surface. The coating composition may be configured to chemically bond with a cured primer composition that includes an epoxy.

A wellbore assembly can include a completion string having a side pocket. A downhole device can be positioned within the side pocket of the completion string. The downhole device can have a first end sized and shaped for coupling to a tool for inserting and removing the downhole device in the side pocket while the completion string is positioned downhole in a wellbore. The downhole device can be an electronic device.

A method for clearing an obstruction in a wellbore may include opening a first choke that is in fluid communication with the wellbore. This may create a first pressure in the wellbore. The first choke may then be closed. If the choke is adjustable, the choke size may be adjusted to a second size and opened. If the choke is fixed, a second choke of a different size is then opened. When the second choke is opened, a second pressure may be created in the wellbore that is different from the first pressure. The second choke may then be closed. For an adjustable choke, the size is changed to either the first size or a third size. For a fixed choke, either the first choke or a third choke that has a different size may be opened. These steps may be repeated until the obstruction in the wellbore is cleared.

A method for clearing an obstruction in a wellbore may include opening a first choke that is in fluid communication with the wellbore. This may create a first pressure in the wellbore. The first choke may then be closed. If the choke is adjustable, the choke size may be adjusted to a second size and opened. If the choke is fixed, a second choke of a different size is then opened. When the second choke is opened, a second pressure may be created in the wellbore that is different from the first pressure. The second choke may then be closed. For an adjustable choke, the size is changed to either the first size or a third size. For a fixed choke, either the first choke or a third choke that has a different size may be opened. These steps may be repeated until the obstruction in the wellbore is cleared.

A distributed control system for a well string includes a first control section configured to be positioned at a first location. The first control section includes a first control module configured to control a first device positioned at the first location, and the first control module includes a first electric actuator configured to control flow of a fluid to the first device based on a first control signal to control the first device. The distributed control system also includes a second control section configured to be positioned at a second location, remote from the first location. The second control section includes a second control module configured to control a second device positioned at the second location, and the second control module includes a second electric actuator configured to control flow of the fluid to the second device based on the second control signal to control the second device.