A well test module is disclosed including a production manifold, a well test manifold, and a plurality of diverter valves, each having an input port coupled to a well inlet, a first output port coupled to the production manifold by a production loop, and a second output port coupled to the well test manifold. The well test module also includes a first flow meter having an input port coupled to a first end of the well test manifold and an output port coupled to the production manifold by a first well test flow line and a second flow meter having an input port coupled to a second end of the well test manifold and an output port coupled to the production manifold by a second well test flow line.

A method includes positioning a downhole acquisition tool in a wellbore in a geological formation. The method includes operating a pump module to gather information for a fluid outside of the downhole acquisition tool that enters the downhole acquisition tool from a first flowline, a second flowline, or both while the downhole acquisition tool is within the wellbore. Operating the pump module includes controlling a valve assembly to a first valve configuration that enables the fluid to flow into the downhole tool via the first flowline fluidly coupled to a first pump module. Operating the pump module includes controlling a valve assembly to a second valve configuration that enables the fluid to flow into the downhole tool via the second flowline fluidly coupled to a second pump module, and selectively using a turnaround module or a crossover portion disposed between the first flowline and the second flowline to permit discharging the fluid from one flowline to the other flowline by actuating a valve associated with the turnaround module when the first pump module or the second pump module is not in use.

The effect of drilling fluids on particular subterranean environments can be analyzed to improve the formation of drilling fluids and additives such as lost circulation materials. A plug can be generated by a particle plugging apparatus by injecting lost circulation material into the particle plugging apparatus. A set of tests to be performed on the plug can be identified. The set of tests can include at least one physical test and at least one electronic test. A test schedule indicating the order in which each test of the set of tests is to be performed can be defined. The set of tests can be executed to generate a testing output. The testing output can be used to generate a three-dimensional network model of the plug.

Systems, devices, and techniques for determining downhole fluid contamination are disclosed. In one or more embodiments, phase-related properties are measured for a reservoir fluid having a determined composition. An equation-of-state (EOS) isselected and/or tuned based, at least in part, on the measured phase-related properties and the tuned EOS is applied to estimate fluid property values for a reference fluid over specified ranges of at least two thermodynamic properties. Contaminant reference data are generated that correlate the estimated fluid property values for the reference fluid with respective contaminant levels. Within a wellbore, a fluid sample is analyzed to determining a fluid property values. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.

Methods may include calculating a formation permeability for a subterranean formation from a combination of dielectric measurements and acoustic measurements, wherein the formation permeability is calculated according to the formula: k.sub.g=a(V.sub.xσ.sub.w/ε.sub.r).sup.b, where V.sub.x is either V.sub.p, V.sub.s, or V.sub.p/V.sub.s, σ is formation conductivity, Ø.sub.w is water-filled porosity, and a and b are constants that are empirically determined for the frequency selected with respect to V.sub.x; and creating a design for a wellbore operation from the calculated formation permeability. Methods may also include obtaining a dielectric measurement from a downhole formation; obtaining an acoustic measurement from a downhole formation; and calculating a formation permeability from a combination of the dielectric measurement and the acoustic measurement.

The present application relates to a permeability evaluation method for hydrate-bearing sediment, including a complex conductivity spectrum obtaining step, a hydrate saturation calculating step based on the spectrum, a formation factor calculating step based on Archie's first law or from the complex conductivity real part, imaginary part and a conductivity of pore water; and a permeability calculating step based on relaxation time, hydrate saturation, hydrate occurrence mode correction factor and formation factor, or based on the polarization amplitude, hydrate saturation, occurrence mode correction factor and formation factor, or based on the CEC, hydrate saturation and occurrence mode correction factor, or based on the pore radius, fractal dimension, hydrate saturation and occurrence mode correction factor. The application allows a large measuring range, low cost and high accuracy, and can accurately obtain the permeability of hydrate-bearing sediment and effectively reflect the micro-pore structure thereof.

A method of predicting behavior or a degradable device of a borehole tool when deployed downhole including introducing a test mass of material identical to the material of the degradable device to the same general location and at a time near to when the degradable device is deployed, removing the test mass from downhole, determining characteristics related to degradation of the test mass, and predicting degradation behavior of the degradable device based on the determined characteristics.

A method includes operating a downhole acquisition tool in a wellbore in a geological formation and performing formation testing using the downhole acquisition tool in the wellbore to determine at least one measurement associated within the geological formation, the wellbore, or both. The downhole acquisition tool includes one or more sensors that may detect the at least one measurement and the at least one measurement includes formation pressure, wellbore pressure, or both. The method also includes using a processor of the downhole acquisition tool to obtain a response characteristic associated with the formation, the wellbore, or both based on oscillations in the at least one measurement and determining at least one petrophysical property of the geological formation, the wellbore, or both, based on the response characteristic. The petrophysical property includes permeability, mud filter cake permeability, or both.

A method and system may include receiving, via one or more sensors in a wellbore formed in a subsurface formation, measurements of a concentration of an interactive component and a concentration of a non-interactive component in a formation fluid from the subsurface formation, wherein the non-interactive component and the interactive component comprise a component in the formation fluid that is non-interactive and interactive, respectively, with respect to a drilling fluid. The method and system may further include determining a level of contamination from a drilling fluid filtrate that contaminates the formation fluid based on the non-interactive component concentration in the formation fluid and the interactive component concentration in the formation fluid.

A method for monitoring one or more formation fluids in a subterranean formation. The method may include disposing a logging while drilling (LWD) system into a wellbore, measuring the one or more formation fluids in the subterranean formation with an electromagnetic (EM) measurement system disposed on the LWD system to form an EM data set, and inverting the EM data set using an information handling system to form a first image of the one or more formation fluids in the subterranean formation. The method may further include disposing the LWD system into the wellbore a second time, taking a second measurement the one or more formation fluids in the subterranean formation with an EM measurement system disposed on the LWD system to form a second EM data set, inverting the second EM data set using the information handling system to form a second image, and comparing the first image to the second.