An apparatus for manipulating an object in a borehole in an earthen formation includes a body configured to be conveyed along the borehole and a plurality of linear actuators disposed in the body and operatively connected to the object. The plurality of linear actuators applies a translational and rotational movement to the object. A related method includes applying a translational and rotational movement to the object using the plurality of linear actuators.

Asphaltene onset pressure of a formation fluid is determined by subjecting the fluid to a plurality of tests where depressurization is conducted at a different depressurization rate for each test while optically monitoring the fluid for asphaltene flocculation. The pressures at which asphaltene flocculation are detected in each test are fit to a curve as a function of depressurization rate, and the curve is extrapolated to a pressure (e.g., 0 psi) to provide the asphaltene onset pressure.

Provided is a downhole rotary slip ring joint, a well system, and a method for accessing a wellbore. The downhole rotary slip ring joint, in one aspect, includes an outer mandrel, an inner mandrel operable to rotate relative to the outer mandrel, a first outer mandrel communication connection coupled to the outer mandrel, a second outer mandrel electrical communication connection coupled to the outer mandrel, and a third outer mandrel hydraulic communication connection coupled to the outer mandrel, the first outer mandrel communication connection, second outer mandrel electrical communication connection, and third outer mandrel hydraulic communication connection angularly offset and isolated from one another, among other features

A method of determining fluid inflow rates within a wellbore comprises determining a plurality of temperature features from a distributed temperature sensing signal originating in a wellbore, determining one or more frequency domain features from an acoustic signal originating the wellbore, and using at least one temperature feature of the plurality of temperature features and at least one frequency domain feature of the one or more frequency domain features to determine a fluid inflow rate at one or more locations along the wellbore.

A method of determining fluid inflow rates within a wellbore comprises determining a plurality of temperature features from a distributed temperature sensing signal originating in a wellbore, determining one or more frequency domain features from an acoustic signal originating the wellbore, and using at least one temperature feature of the plurality of temperature features and at least one frequency domain feature of the one or more frequency domain features to determine a fluid inflow rate at one or more locations along the wellbore.

A method of perforating a wellbore is provided. The method includes generating a shockwave that propagates throughout said wellbore by firing a perforation device at a perforating direction, and measuring the shockwave at a fiber optic cable in the wellbore using the fiber optic cable. The method further includes determining an orientation of the fiber optic cable relative to the perforating direction based on the shockwave and the perforating direction, and changing the perforating direction based on the orientation of said the optic cable for a subsequent perforation of the wellbore to minimize damage to the fiber optic cable during the subsequent perforation. The fiber optic cable is an existing cable that has been deployed before the method starts.

According to embodiments disclosed herein, a method of monitoring a gel fluid composite may include directing the gel fluid composite into a wellbore extending into a subsurface where the wellbore has one or more downhole fractures so that the gel fluid composite enters the one or more downhole fractures, transforming the gel fluid composite from an aqueous phase to a gel phase, irradiating light onto the gel fluid composite so that the fluorescent compounds emit one or more photons, and detecting the one or more photons using a detection device. The gel fluid composite may include a nanosilica gel that includes silica nanoparticles and an activator, wherein the silica nanoparticles have a maximum cross-sectional dimension of from 3 nm to 100 nm, and one or more fluorescent compounds, wherein the one or more fluorescent compounds are dispersed in the nanosilica gel, bonded to the silica nanoparticles, or both.

According to embodiments disclosed herein, a method of monitoring a gel fluid composite may include directing the gel fluid composite into a wellbore extending into a subsurface where the wellbore has one or more downhole fractures so that the gel fluid composite enters the one or more downhole fractures, transforming the gel fluid composite from an aqueous phase to a gel phase, irradiating light onto the gel fluid composite so that the fluorescent compounds emit one or more photons, and detecting the one or more photons using a detection device. The gel fluid composite may include a nanosilica gel that includes silica nanoparticles and an activator, wherein the silica nanoparticles have a maximum cross-sectional dimension of from 3 nm to 100 nm, and one or more fluorescent compounds, wherein the one or more fluorescent compounds are dispersed in the nanosilica gel, bonded to the silica nanoparticles, or both.

A method for determining microseismic events. The method may include measuring a seismic travel time of a microseismic event with a fiber optic line disposed in a first wellbore, forming a probability density function for the microseismic event based at least in part on the seismic travel time measurement, modifying the probability density function by applying one or more constraints to form a modified probability density function, identifying one or more most probable source locations from the modified probability density function, and forming a microseismic event cloud from the one or more most probable source locations.

A method creates a fluid communication path between a first production well and a second production well. At least one hydraulic fracture intersects the first production well and is separated from the second production well by a wall thereof. The method includes identifying, from the second production well, a location of the hydraulic fracture of the first production well, and perforating the wall of the second production well at the identified location. The perforating creates the fluid communication path between the production wells. Injection of fracking fluid and proppant at the first production well allows for additional fluids to be extracted from the second production well, thus generating a flow between the two production wells through the hydraulic fracture.