Abstract: Herein disclosed are methods and systems related to processes for injection wells generally utilized in the oil and gas industry. The methods herein include a method of estimating the relative cumulative volume of fluids injected into multiple zones of an injection well located in a hydrocarbon reservoir, the injection well including a plurality of zones. The method comprises injecting fluid into a wellbore of the injection well. The method further includes measuring temperature at points along the wellbore to produce a warm-back data set that includes data for a plurality of times and depths. The method also includes modifying an initial geotherm using only data from the warm-back data set that is in a middle-time region (MTR) of the warm-back data set to produce a calculated pseudo-geotherm. The calculated pseudo-geotherm may be used to estimate a volume of fluid injected into each of the plurality of zones.

Abstract: Methods and systems for measuring pipe parameters using guided acoustic wave modes are provided. The method includes receiving data corresponding to an acoustic signal, wherein the data are obtained by transmitting an excitation pulse at a specified frequency and detecting the resulting acoustic signal using an acoustic transducer attached to the outer surface of the pipe wall. The method includes analyzing the data to identify guided acoustic wave modes including at least two of: a C-SH acoustic wave mode that travels within the pipe wall; a C-LT acoustic wave mode that travels within the near-surface region of the pipe wall; and/or a CA acoustic wave mode that travels within the pipe cavity. The method includes calibrating the parameter measurement using the C-SH acoustic wave mode and determining the parameter measurement based on the phase velocity and/or the amplitude of the C-LT acoustic wave mode and/or the CA acoustic wave mode.

Abstract: A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid in a semi-continuous or pulsed manner at one or more locations in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A time of flight model is used to determine, for a plurality of points of interest, a fluid flow direction, bulk flow rate and/or a cumulative flow rate contribution.

Abstract: Methods of characterizing acoustic output from a hydrocarbon well and hydrocarbon wells that include controllers that perform the methods are disclosed herein. The methods include receiving the acoustic output, determining a plurality of acoustic fingerprints, and electronically clustering the plurality of acoustic fingerprints. The acoustic output includes information regarding a plurality of sound events, and each sound event of the plurality of sound events includes at least one corresponding sound detected at the hydrocarbon well. The plurality of acoustic fingerprints includes a corresponding acoustic fingerprint for each sound event of the plurality of sound events. The electronically clustering includes utilizing a clustering algorithm to generate a plurality of acoustic event clusters.

Abstract: Cable guides that support a fiber optic cable relative to a tube, hydrocarbon conveyance systems including the cable guides, and methods of acoustically probing an elongate region. The cable guides include a cable retention structure with a first retention region configured to align a first diffraction grating along a first sensing axis and a second retention region configured to align a second diffraction grating along a second sensing axis that is nonparallel to the first sensing axis. The tube defines a tubular conduit configured to convey a hydrocarbon. The hydrocarbon conveyance systems include a tube, a distributed acoustic sensor, and a cable guide. The methods include transmitting an initiated optical signal and receiving a reflected optical signal that includes reflected portions that are reflected by a first diffraction grating and a second diffraction grating. The methods further include analyzing the reflected optical signal to detect an applied mechanical strain.

Abstract: Methods of increasing efficiency of plunger lift operations and hydrocarbon wells that perform the methods are disclosed herein. The methods include monitoring an acoustic output from the hydrocarbon well. The methods also include calculating a plunger speed of a plunger of the hydrocarbon well as the plunger travels toward a surface region and calculating a discharge duration of a liquid discharge time period during which liquid is discharged from the hydrocarbon well.

Abstract: Superterranean acoustic networks, methods of forming superterranean acoustic networks, and methods of operating superterranean acoustic networks are disclosed herein. The superterranean acoustic networks include superterranean hydrocarbon infrastructure that extends above a ground surface, defines a waveguide, and contains a fluid. The infrastructure also includes a plurality of acoustic communication nodes spaced-apart along the superterranean hydrocarbon infrastructure. Each acoustic communication node of the plurality of acoustic communication nodes includes an acoustic transmitter and an acoustic receiver. The acoustic transmitter is configured to generate a generated acoustic signal and to supply the generated acoustic signal to the waveguide. Responsive to receipt of the generated acoustic signal, the waveguide is configured to propagate a propagated acoustic signal there through.

Abstract: A method of measuring a pressure of a fluid adjacent a wall of a pipe or vessel. A transducer is attached to the wall of the pipe or vessel. A signal is transmitted by the transducer at a characteristic frequency via a plurality of guided wave modes. The characteristic frequency is a frequency at which the guided wave modes are separated in time from each other when received. The signal is received after the plurality of guided wave modes travel in or through the wall a predetermined number of times. The signal has a signal receipt time after the predetermined number of times. The pressure of the fluid is calculated using the signal receipt time.

Abstract: Methods and systems for measuring pipe parameters using guided acoustic wave modes are provided. The method includes receiving data corresponding to an acoustic signal, wherein the data are obtained by transmitting an excitation pulse at a specified frequency and detecting the resulting acoustic signal using an acoustic transducer attached to the outer surface of the pipe wall. The method includes analyzing the data to identify guided acoustic wave modes including at least two of: a C-SH acoustic wave mode that travels within the pipe wall; a C-LT acoustic wave mode that travels within the near-surface region of the pipe wall; and/or a CA acoustic wave mode that travels within the pipe cavity. The method includes calibrating the parameter measurement using the C-SH acoustic wave mode and determining the parameter measurement based on the phase velocity and/or the amplitude of the C-LT acoustic wave mode and/or the CA acoustic wave mode.

Abstract: A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid at a first location in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A simulated heat flow profile is generated from a wellbore model. The simulated heat flow profile is compared to the measured temperature of the fluid at the one or more sensing locations. An inversion model is used to determine, for a plurality of points of interest, a fluid flow direction and/or a cumulative flow rate contribution.

Abstract: A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid in a semi-continuous or pulsed manner at one or more locations in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A time of flight model is used to determine, for a plurality of points of interest, a fluid flow direction, bulk flow rate and/or a cumulative flow rate contribution.

Abstract: A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid at a first location in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A simulated heat flow profile is generated from a wellbore model. The simulated heat flow profile is compared to the measured temperature of the fluid at the one or more sensing locations. An inversion model is used to determine, for a plurality of points of interest, a fluid flow direction and/or a cumulative flow rate contribution.