Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. In some embodiments, OBM filtrate contamination may be determined from downhole saturation pressure measurements during pumpout of a fluid.

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. In some embodiments, OBM filtrate contamination may be determined from downhole saturation pressure measurements during pumpout of a fluid.

Techniques implementing and/or operating a system includes a pipe segment and a test head assembly secured to the pipe segment. The pipe segment includes tubing that defines a pipe bore through the pipe segment and a fluid conduit in a tubing annulus of the pipe segment. The test head assembly includes barrier material poly welded to the tubing of the pipe segment to facilitate sealing the fluid conduit defined in the tubing annulus from environmental conditions external to the tubing of the pipe segment and a fluid port fluidly connected to the fluid conduit defined within the tubing annulus to enable integrity of the tubing to be tested at least in part by flowing a test fluid into the fluid conduit defined in the tubing annulus via the fluid port, extracting fluid from the fluid conduit defined in the tubing annulus via the fluid port, or both.

Techniques implementing and/or operating a system includes a pipe segment and a test head assembly secured to the pipe segment. The pipe segment includes tubing that defines a pipe bore through the pipe segment and a fluid conduit in a tubing annulus of the pipe segment. The test head assembly includes barrier material poly welded to the tubing of the pipe segment to facilitate sealing the fluid conduit defined in the tubing annulus from environmental conditions external to the tubing of the pipe segment and a fluid port fluidly connected to the fluid conduit defined within the tubing annulus to enable integrity of the tubing to be tested at least in part by flowing a test fluid into the fluid conduit defined in the tubing annulus via the fluid port, extracting fluid from the fluid conduit defined in the tubing annulus via the fluid port, or both.

An aqueous feed stream having a first total dissolved solids (TDS) level is flowed to a forward osmosis separator. The aqueous feed stream includes seawater. An aqueous draw stream having a second TDS level is flowed to the forward osmosis separator. The second TDS level is greater than the first TDS level. A disposal stream and an injection fluid stream is produced by the forward osmosis separator by allowing water to pass from the aqueous feed stream to the aqueous draw stream through a membrane of the forward osmosis separator based on a difference between the first TDS level and the seconds TDS level. The injection fluid stream is flowed from the osmosis separator to a subterranean formation.

An aqueous feed stream having a first total dissolved solids (TDS) level is flowed to a forward osmosis separator. The aqueous feed stream includes seawater. An aqueous draw stream having a second TDS level is flowed to the forward osmosis separator. The second TDS level is greater than the first TDS level. A disposal stream and an injection fluid stream is produced by the forward osmosis separator by allowing water to pass from the aqueous feed stream to the aqueous draw stream through a membrane of the forward osmosis separator based on a difference between the first TDS level and the seconds TDS level. The injection fluid stream is flowed from the osmosis separator to a subterranean formation.

Methods for determining reservoir characteristics of a well can include receiving a first core from the well; performing an experiment to determine the wave velocity associated with a first direction of the first core, the experiment including: transmitting an ultrasonic wave through the first core in the first direction; receiving the transmitted ultrasonic wave; and determining a directional wave velocity of the first core based on the transmitted ultrasonic wave and the received transmitted ultrasonic wave, wherein the directional wave velocity represents a wave velocity along the first direction; rotating the first core about a longitudinal axis of the first core; and performing the experiment along a second direction of the first core.

A system may include an electromagnetic (EM) logging tool for inspecting downhole tubulars. The EM logging tool may include a mandrel, at least one low-frequency transmitter coil disposed on the mandrel, at least one-low frequency receiver coil disposed on the mandrel, and at least one-high frequency sensor configured to measure one or more electromagnetic properties of a tubular.

A method may include obtaining caliper log data regarding a well. The method may further include determining, using a descaling model and the caliper log data, various predicted caliper log values for a descaled well. The descaled well may correspond to the well following a scale treatment. The method may further include determining whether the descaled well satisfies a predetermined criterion based on the predicted caliper log values. The method may further include determining, in response to determining that the descaled well fails to satisfy the predetermined criterion, a tubular replacement for the well. The method may further include transmitting, to a control system, a command that implements the tubular replacement.

A method and system for estimating a resistivity of a formation. A method for estimating a resistivity of a formation may comprise disposing a downhole tool into a borehole, wherein the downhole tool comprises a pad, an injector electrode, and a return electrode, injecting a current signal into the formation from the injector electrode, measuring a voltage signal between the injector electrode and the return electrode; and determining a formation resistivity and a formation dielectric constant from at least one of the voltage signal, at least one property of the downhole tool, and at least one property of the borehole. A system for estimating a resistivity of a formation may comprise a downhole tool. The downhole tool may comprise a pad, wherein the pad comprises an injector electrode and a return electrode. The system may further comprise a conveyance for disposing the downhole tool in a borehole and an information handling system.