A visualization system and method for a multiphase fluids displacement seepage experiment with large viscosity difference in a complex pore structure. The visualization system includes: an injection pump assembly, a visualized complex pore model, a vacuum pressure pump and an image acquisition device; the system and method are printed by a 3D printing device to form the visualized complex pore model with at least two permeability, and displacement fluid mediums of different viscosities are injected into the visualized complex pore model through different injection pumps during an experiment, so that not only is the penetration of the same viscosity in the complex pore structure with different permeability observed, but also the displacement and plugging effect of different viscosities successively entering the complex pore structure with different permeability is realized.

Various embodiments described herein relate to apparatuses and methods for detecting fluid particles and their characteristics. In various embodiments, a device for detecting fluid particles and their characteristics may comprise a fluid composition sensor configured to receive a volume of fluid. The fluid composition sensor has a collection media housing configured to receive a portion of a collection media, a pump for moving a volume of fluid over the collection media housing, an imaging device configured to capture an image of particles on the collection media, and a particle matter mass concentration calculation circuitry configured to calculate a total particle matter mass. The particle matter mass concentration calculation circuitry is connected with the imaging device and the pump. The particle matter mass concentration calculation circuitry is configured to adjust the volume of fluid over the collection media housing.

The present disclosure relates, according to some embodiments, to methods of marker based direct integrity testing of at least one membrane comprising: (a) dosing a feed fluid of a loop with at least one marker comprising at least one challenge particle, the loop comprising: the feed fluid; a pump comprising an outlet stream; a membrane module comprising the at least one membrane and a membrane module outlet stream, wherein the membrane module is in fluid communication with the outlet stream; a marker recycle stream in fluid communication with the membrane module outlet stream and the pump; and a means to measure particle concentrations; (b) circulating the feed fluid through the membrane module at least once to produce a filtrate comprising a filtered at least one marker; (c) measuring a filtrate particle concentration of the filtered at least one filtered marker in the filtrate to produce a filtrate concentration measurement; and (d) calculating a log removal value from the filtrate concentration measurement and the feed concentration measurement; wherein the log removal value is less than about 3 μm.

A system for determining particle size of a quantity of a sample material contained in a sample material holder is disclosed, where the sample material is made up a plurality of the particles. The system may incorporate a pressure regulating subsystem for receiving a first pressurized airflow signal and regulating the first pressurized airflow signal to a second pressurized airflow signal having a pressure lower than the first pressurized airflow signal, the second pressurized airflow signal configured to be input to a first end of the sample material holder. A mass airflow transducer may be incorporated for determining a flow rate representing an air flow value entering the sample material holder. A control module uses the air flow value in combination with the pressure differential value and mathematically determining a dimension of the particles making up the sample material.

A method for determining properties of different cation exchange sites in a rock core sample may include providing a rock core sample that is in either a preserved state or a non-preserved state, wherein a preserved form of the rock core sample includes a plurality of indigenous exchangeable cations adsorbed onto the cation exchange sites, a plurality of cation exchange sites occupied by a crude oil, and one or more fluids occupying pore spaces in the rock core sample; subjecting the rock core sample to a plurality of coreflooding steps, the plurality of coreflooding step displacing the plurality of indigenous exchangeable cations and the one or more fluids in at least two separate coreflooding steps to render the rock core sample clean of indigenous exchangeable cations; and determining an amount of indigenous exchangeable cations adsorbed onto the cation exchange sites.

In some embodiments, a system includes a housing having a cavity defined therein for holding a test sample, a first inlet in fluid communication with the cavity to deliver fluid to the test sample, a second inlet in fluid communication with the cavity to deliver fluid to the test sample, the first inlet configured to deliver fluid to the test sample in a direction substantially perpendicular to a direction that the second inlet is configured to deliver fluid to the test sample, an outlet in fluid communication with the cavity to receive fluid from the test sample, and a force applicator configured to apply compressive force to the test sample within the cavity. The force applicator forms a seal with the housing while applying compressive force to the test sample. The system also comprises at least one sensor configured to, while fluid flows from at least one of the inlets through the test sample to the outlet, determine a fluid characteristic, a test sample characteristic, or any combination thereof.

An apparatus for evaluating gas barrier properties, a support having a polymer for supporting a sample, a chamber on a permeation side, and a detection unit, the support being joined to the opening of the chamber on a permeation side; in which a polymer film is provided between the support and a sample; a chamber on a supply side is provided, being disposed so as to be closably attachable to the sample and able to go up and down; and an external chamber covers a region interposed between the polymer film and the support; and a method of evaluating gas barrier properties using the same.

An apparatus for evaluating loss circulation material (LCM) in loss circulation zones is described. The apparatus includes a drilling fluid reservoir that can carry a wellbore drilling fluid. The apparatus includes a LCM reservoir that can carry a LCM. The apparatus includes a spacer fluid reservoir that can carry a spacer fluid. The apparatus includes a LCM test cell that includes a disk member that includes multiple openings. The disk member represents a loss circulation zone in a subterranean zone in which a wellbore is drilled using the wellbore drilling fluid. The LCM test cell is fluidically connected to the drilling fluid reservoir, the LCM reservoir and the spacer fluid reservoir. The LCM test cell is configured to fluidically receive a quantity of LCM from the LCM reservoir and to evaluate an ability of the LCM to decrease loss circulation through the loss circulation zone.

A method for characterizing wettability of a porous medium is described. A core sample of the porous medium is secured in a core holder, which includes a first end and a second end. A model of the core sample and a pore volume of the core sample are obtained. A wetting phase is displaced from the core sample by supplying a non-wetting phase at one end of the core holder. The non-wetting phase is displaced from the core sample by supplying the wetting phase at one end of the core holder. A saturation profile of the core sample is determined based on cross-sectional images of the core sample. A wettability index value is calculated at least based on a comparison of the saturation profile and the model of the core sample.

A physical simulation and calibration device and method for formation pressure testing. The device has a rock core arranged in a rock core clamper, a confining pressure simulation module, formation pressure simulation module, annular pressure simulation module, suction system, thrust force simulation module and drive control system. The thrust force simulation module has a thrust rod which penetrates through a cavity wall on one side of the clamper. The front end of the thrust rod has a simulation probe. The suction system is connected to the thrust rod. The confining pressure simulation module, formation pressure simulation module, annular pressure simulation module, thrust force simulation module and suction system are all connected with the drive control system. The device and method simulate a physical environment of formation pressure testing to achieve physical simulation of formation pressure testing. A formation pressure tester can be corrected and calibrated.