A downhole tool comprises at least one inlet and a first pump coupled to the at least one inlet via a first flow line. The first pump is to pump at a first pump rate to extract fluid via the at least one inlet from a subsurface formation in which a borehole is created and in which the downhole tool is to be positioned. A sample chamber is coupled to the inlet via a second flow line, and a second pump is coupled to the inlet via the second flow line. The second pump is to pump at a second pump rate to extract the fluid via the at least one inlet from the subsurface formation and for storage in the sample chamber. The first pump rate is greater than the second pump rate.

A method includes treating a reservoir with a damaged near wellbore region (NWR), including introducing a liquid foam treatment into a wellbore proximate to the damaged NWR, where the liquid foam treatment has a solution medium and nanobubbles, transmitting an acoustic wave towards the damaged NWR such that the nanobubbles collapse, causing fluid flow pathways to form for hydrocarbon production.

A system includes a solution generation tool for generating a liquid foam treatment, where the liquid foam treatment has a solution medium and nanobubbles, where the nanobubbles migrate along a concentration gradient, and an acoustic signal generator transmits an acoustic signal. The system also includes a downhole tool signally coupled to the acoustic signal generator fluidly coupled to the solution generation tool, and the downhole tool transmits an acoustic wave into an NWR and introduces the liquid foam treatment into the wellbore proximate to the NWR.

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 drainage bottle apparatus includes a cylindrical body portion with a base, a neck portion, a receptor opening located at a rim, a first and a second threaded inner perimeter surface, a removable sieve having a sieve outer perimeter rim thread, and a sieve base. The sieve outer perimeter rim thread mates with the second threaded inner perimeter surface. A method for extracting a rock plug sample includes using the drainage bottle apparatus in combination with a sample jar containing a rock plug sample and a liquid material. The sample jar includes a sample jar outer perimeter surface thread that mates with the first threaded inner perimeter surface of the neck portion and is turned over so as to drain the liquid material thereby separating the liquid material from the rock plug sample and the rock plug sample, now dried, may be extracted.

Fluid holdups within a downhole sampling tool are identified by comparing high- and low-resolution measurements of fluid samples.

A method to manipulate a well comprising providing an apparatus (60) in a well (14) below a packer (22) or other annular sealing device, the apparatus comprising a container (68) having a volume of gas which is sealed at the surface and nm into the well, such that the pressure in the container (68) is at a lower pressure than the surrounding well. When the apparatus is below the packer, a wireless control signal, is sent to operate a valve assembly (62) to selectively allow fluid to enter the container whereby at least 50 litres of fluid is drawn into the container. In this way, the apparatus can be used independent of perforating guns, to clear perforations or other areas in the well or may be used for a variety of tests such as an interval test, drawdown test or a connectivity test such as a pulse or interference test.

A multi-pump integrated mixed fluid delivery device includes a hollow cylindrical casing, a hydraulic drive part, a power part, a sample part and a pipeline unit. The hydraulic drive part, the power part, the sample part and the pipeline unit are provided within the casing in sequence. The hydraulic drive part includes multiple hydraulic plunger pumps. The power part includes a dual-shaft motor, wherein an output shaft of the dual-shaft motor is connected with the hydraulic plunger pumps. The sample part includes a lead screw, a screw nut, a piston rod and a sample chamber, wherein one end of the lead screw is connected with another output shaft of the dual-shaft motor, the screw nut is sleeved on the lead screw, the piston rod is fixedly connected with the screw nut. The sample chamber is configured to accommodate a sample.

A vortex suppression device (10) for a fluid flowing along a pathway (A-E), including: an elongate body with an outer surface having an elongate leading section and an elongate trailing section along the length of the elongate body, in relation to a direction of fluid flow (A-E) when the device is located in the pathway, the elongate body having at least one channel (24a-24d, 26a, 26b) which extends from the elongate leading section to the elongate trailing section of the elongate body, the channel (24a-24d, 26a, 26b) being configured so that in use, when the device is in the pathway, the channel (24a-24d, 26a, 26b) allows fluid flow (J) towards the trailing section that disrupts the formation of vortices (D).

The present invention is related to computer implemented method for characterizing a target fluid of a hydrocarbon reservoir under uncertainty providing a set of fluid properties from a limited amount of information.

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) is selected 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 determine a fluid property value. A contaminant level is identified that corresponds within the contaminant reference data to the determined fluid property value of the fluid sample.