Systems and methods for measuring the viscosity of a fluid may comprise a rotor cup having an inner chamber; a first bob rotatably disposed within a first region of the inner chamber; and a second bob rotatably disposed within a second region of the inner chamber, wherein the second bob rotates relative to the first bob based on a difference in viscosity of fluid in the first region and the second region.

Embodiments described herein include a system for generating a drainage radius log per well that includes a computing device that receives well data associated with a plurality of wells, utilizes the well production data to calculate a value for cumulative liquid produced by each of the plurality of wells for a predetermined time period, and utilizes at least a portion of the well data to calculate a fractional contribution for each of the plurality of wells. In some embodiments the computing device utilizes the value for cumulative liquid produced for each of the plurality of wells and the fractional contribution to calculate a cumulative liquid production for each of the plurality of wells, utilizes the cumulative liquid production to calculate the drainage radius log for each of the plurality of wells, and outputs the drainage radius log for display.

A chelating agent can be used to enhance secondary hydrocarbon-fluid recovery during waterflooding operations. A composition can include a fluid and a chelating agent. The chelating agent can increase the viscosity of the fluid, which can enhance the efficacy of the waterflooding operations. The chelating agent can also form complexes with divalent cations in precipitates and solids formed by the divalent cations. The complexes can keep the cations in a soluble form until the composition exits the production well, which can prevent precipitates from forming in the production well and blocking pore throats in the production well.

Hydrocarbon wells and methods of probing a subsurface region of the hydrocarbon wells. The hydrocarbon wells include a wellbore, a downhole sensor storage structure, and a detection structure. The wellbore may extend within a subsurface region and between a surface region and a downhole end region. The downhole sensor storage structure is configured to release a flowable sensor into a wellbore fluid that extends within the wellbore, and the flowable sensor may be configured to collect sensor data indicative of at least one property of the subsurface region. The detection structure may be configured to query the flowable sensor to determine the at least one property of the subsurface region. The methods include releasing a flowable sensor, collecting sensor data with the flowable sensor, and querying the flowable sensor.

An example CO.sub.2 monitoring systems is configured for monitoring levels of CO.sub.2 in a wellbore. A CO.sub.2 monitoring system may include one or more laser monitoring tools. A laser monitoring tool may include an optical element to output a laser beam, a detector to receive the laser beam, a first chamber housing the optical element and detector, and a second chamber including an inlet and an outlet receive and release, respectively, wellbore fluid. The first chamber may be in fluid connection with second chamber via a gas permeable membrane. Gas may permeate from second chamber into first chamber. Gas in the first chamber is subjected to a laser beam. Absorption of light by the gas is measured, and content of gas is determined based at least in part on the amount of light absorption by the gas.

A system can determine a temperature profile based on a prior production temperature profile and a reference start point pressure for a well. The system can virtually divide the well into a plurality of sections including uphill sections and downhill sections. The system can determine a gas-oil interface depth for each section of the plurality of sections from a water-oil ratio and a gas-oil ratio based on the temperature profile and the reference start point pressure. The system can determine an oil-water interface depth for each section of the plurality of sections from the gas-oil ratio and the water-oil ratio based on the temperature profile and the reference start point pressure.

The systems and method described in this specification relate to a method for determining a residual oil saturation of a reservoir. The method includes obtaining a plurality of rock samples from the reservoir; determining a permeability of each of the rock samples; measuring a fluid viscosity of oil in the reservoir; estimating a location-specific permeability of the reservoir across the reservoir based on the permeability of each of the rock samples; determining a location-specific displacing velocity of the reservoir based on a function of the location-specific permeability and the fluid viscosity of the oil; determining the residual oil saturation of the reservoir based on the location-specific displacing velocity using Franklin's equation; and predicting a recovery of the oil from the reservoir using the residual oil saturation in a computational model of the reservoir.

An apparatus for detecting one or more properties of a downhole fluid includes a housing. The apparatus also includes a location-sensitive optical detector, arranged within a chamber formed by the housing. The apparatus further includes a light source, arranged within the chamber. The apparatus also includes a lens, positioned at an end of the housing, the lens preferably having a flat side and a curved side, the flat side positioned proximate the chamber to position the flat side closer to the light source than the curved side. The apparatus further includes a mirror, arranged outside the housing.

Systems, methods, and computer-readable media that improve flow of a multiphase mixture in a fluid transport system by determining pressure drop of low-liquid loading flows are provided. The method includes obtaining physical dimensions of a pipe that transports a multiphase flow. The method also includes obtaining physical parameters of the multiphase flow in the pipe. The method further includes determining an effective toughness of a liquid film of the multiphase flow on an interior wall of the pipe using the physical dimensions of the pipe and the physical parameters of the multiphase flow. Additionally, the method includes determining a pressure drop in the pipe using the effective roughness of the liquid film. Moreover, the method includes determining operating parameters of the system based on the pressure drop in the pipe.

Described is a device for measuring fluid density. The device is a flow meter including a housing with one side configured to mount to a flow conduit and define an outlet flow orifice near one end of the housing. The other side defines an inlet flow orifice near another end of the housing. The housing permits fluid to be introduced into the inlet flow orifice, flow through a flow cavity, and pass from the outlet flow orifice. The flow meter also includes a sensor head near the outlet flow orifice. The sensor head vibrates at a frequency upon introduction of electrical power while in contact with a fluid, detects the vibration frequency of the sensor head, and transmits the detected vibration frequency, which is associated with a density of the fluid. A system and method for determining a fluid density of a fluid using the described device is also disclosed.