Abstract: A method to measure flow rate and water cut (WC) of a well includes: from a data set, for depths of two pressure gauges installed in the well, acquiring simulated pressures and corresponding simulated flow rates and simulated WCs; measuring pressures at the depths of the two pressure gauges via the two pressure gauges; comparing the measured pressures with the acquired simulated pressures, by calculating error values for the measured pressures with respect to the acquired simulated pressures; obtaining simulated flow rates and simulated WCs that correspond to the calculated error values not greater than a threshold; and averaging the simulated flow rates and simulated WCs that correspond to the simulated pressures that have the error values not greater than the threshold, to acquire an estimated flow rate and an estimated WC at the depths of the two pressure gauges.

Abstract: A well system includes a wellbore, production tubing extended into the wellbore and thereby defining an annulus between the production tubing and an inner wall of the wellbore, and a side pocket mandrel interposing upper and lower sections of the production tubing and including a body that provides a lateral projection extending radially outward from the body, and a pocket defined within the lateral projection. The well system further includes a chemical vessel receivable within the pocket and operable to discharge an injection fluid stored within the chemical vessel into the production tubing via one or more apertures provided in the chemical vessel.

Abstract: A well completion includes a production tubing and a well tool. The production tubing includes an elongate cylindrical body including an inner diameter and having a length. The production tubing includes a completion profile formed at a location along the length of the body. An inner diameter of the completion profile is equal to an inner diameter of the body. The well tool is attached to the completion profile. The production tubing and the well tool are configured to perform a hydrocarbon production operation upon installation within a wellbore formed through a subterranean zone.

Abstract: A wellbore system includes a wellhead positioned at a well surface and capping a wellbore extending from the wellhead, and a plurality of strings of casing arranged within the wellbore and extending from the wellhead. The plurality of strings of casing include an intermediate casing, and a production casing arranged within the intermediate casing and thereby defining a casing-casing annulus between the production casing and the intermediate casing. Production tubing extends from the wellhead and is arranged within the production casing, and corrosion inhibiting diesel fluid is present within the casing-casing annulus and thereby forms a corrosion-inhibiting barrier within the wellbore.

Abstract: A well system includes a wellhead arranged at a well surface and having a wellbore extending therefrom, the wellhead including a production tubing head housing, production casing extending from the wellhead and into the wellbore, production tubing extending from the production tubing head housing and into the production casing and thereby defining a tubing-casing annulus between the production tubing and the production casing, one or more side outlets extending outwardly from the production tubing head housing at an acute angle and in fluid communication with the tubing-casing annulus, and a downhole assembly conveyable into the tubing-casing annulus via the one or more side outlets and configured to obtain direct measurements of the tubing-casing annulus.

Abstract: A sensor assembly includes a position measurement sensor, a slickline, and a processor. The position measurement system measures angular velocity of the sensor assembly inside a wellbore that extends in an axial direction. The slickline raises and lowers the position measurement sensor in the wellbore. The processor executes a series of measurement units including: an inclination measurement unit, a coordinate measurement unit, a depth measurement unit, and a data storage unit. The inclination measurement unit determines an inclination of the position measurement sensor. The coordinate measurement unit determines radial coordinates of the position measurement sensor. The depth measurement unit determines a real-time depth level of the position measurement sensor. Each of the inclination, the radial coordinates, and the real-time depth level are determined from the angular velocity.

Abstract: A well system includes a wellbore penetrating a subterranean formation, production tubing extended into the wellbore and terminating at a completion string, and one or more inflow control devices forming part of the completion string. The inflow control device includes a base pipe defining one or more first flow ports and one or more second flow ports axially spaced from the first flow ports. A first flow regulation device is arranged within the base pipe and actuatable to expose or occlude the first flow ports, and a second flow regulation device is arranged within the base pipe and actuatable to expose or occlude the second flow ports. A downhole shifting device is operable to independently manipulate a position of the first and second flow regulation devices and thereby selectively expose or occlude the first or second flow ports.

Abstract: A well completion includes a production tubing and a well tool. The production tubing includes an elongate cylindrical body including an inner diameter and having a length. The production tubing includes a completion profile formed at a location along the length of the body. An inner diameter of the completion profile is equal to an inner diameter of the body. The well tool is attached to the completion profile.

Abstract: An apparatus for obtaining fluids via a well includes an outer tubing disposed in the well and set at a shallow reservoir comprising a first fluid, and an inner tubing disposed concentrically within the outer tubing and set at a deeper reservoir further downhole than the shallow reservoir. The deeper reservoir has a second fluid, where a first packer is disposed between the outer tubing and an external tubing and disposed above the shallow reservoir, and a second packer is disposed between the outer tubing and the inner tubing and disposed above the deeper reservoir. The second packer blocks an annulus through which the first fluid is extracted via the outer tubing. The first fluid is obtained from the shallow reservoir and the second fluid is obtained from the deeper reservoir by drilling via the well.

Abstract: Techniques for developing a hydrocarbon well that include: determining a skin increase threshold; collecting historical production data for hydrocarbon wells; determining, based on the data, skin profiles for the wells; identifying, in response to changes in skin that exceed the threshold, wells as candidates for stimulation; for each of the candidate wells: determining an observed production rate; determining a predicted production rate that corresponds to a skin of zero; determining a cost of stimulation to remediate the well; determining, based on the observed and predicted production rates, a predicted increase in production attributable to stimulation; and determining, based on the cost of stimulation and the predicted increase, a marginal production cost for increased production; selecting, based on the marginal production costs of the candidate wells, a well to be stimulated; and conducting a stimulation of the well selected.

Abstract: An apparatus for obtaining fluids via a well is disclosed. The apparatus includes an outer tubing disposed in the well and set at a shallow reservoir comprising a first fluid, an inner tubing disposed concentrically within the outer tubing and set at a deeper reservoir further downhole than the shallow reservoir, the deeper reservoir comprising a second fluid, a first packer disposed between the outer tubing and an external tubing and disposed above the shallow reservoir, and a second packer disposed between the outer tubing and the inner tubing and disposed above the deeper reservoir, wherein the second packer blocks an annulus through which the first fluid is extracted via the outer tubing. The first fluid is obtained from the shallow reservoir and the second fluid is obtained from the deeper reservoir by drilling via the well.

Abstract: The check valve positioned within a production tubing string is configured to open when a differential pressure across the check valve exceeds a specified opening differential pressure. With the check valve closed, a specified volume of gas is flowed from the production tubing string, thereby decreasing the pressure within the production tubing string from a first wellhead pressure to a second, lesser wellhead pressure. Hydrostatic pressure within the production tubing string at the check valve is increased by flowing a specified volume of water into the production tubing string above the check valve to at least partially replace the specified volume of gas. After flowing the water, a specified volume of treatment fluid is injected into the production tubing string at an injection pressure less than the first wellhead pressure and greater than the second wellhead pressure, thereby opening the check valve and flowing the treatment fluid downhole.

Abstract: Systems and methods include a computer-implemented method for selecting well candidates. Pre- and post-stimulation production rates are determined for initial stimulation job candidates of an oil well. A field performance decline factor is determined as an average slope of post-job monthly rate changes for each well determined using a performance decline equation. A time period that a stimulated well will reach its pre-stimulation oil production rate is determined. The performance decline equation is re-executed until a future additional production rate gain approaches zero. A monthly additional production rate is determined based on the field performance decline factor, and a cumulative additional production rate for each candidate is determined. A best candidate is determined based on comparing the cumulative additional production rate for each candidate.

Abstract: A pressure bleed-off module for an oil well includes: an inlet receiving fluid from an annulus vent of the well; an outlet sending the received fluid to a kill valve of the well; and two paths coupled in parallel between the inlet and the outlet. Each path channels a flow of the received fluid from the inlet to the outlet and includes: a pressure relief valve dividing the path into an inlet side coupled to the inlet and an outlet side coupled to the outlet, opening when the pressure of the fluid in the inlet side exceeds a threshold, and closing when the inlet fluid pressure is below the threshold; pressure gauges measuring the inlet fluid pressure and the pressure of the fluid in the outlet side; a pressure recorder recording the measured inlet and outlet fluid pressures; and a sampling point for draining the fluid in the outlet side.

Abstract: Provided are techniques that include determining a first set of operating parameters for a hydrocarbon well for a first period; determining, based on the first set of operating parameters, a skin factor (S1); determining, based on the skin factor (S1), a well model for the well; determining, a second set of operating parameters for the well for a second period; determining, based on the second set of operating parameters, well performance characteristics for the second period that include: a well pressure and a production flowrate for the second period of time; determining that the well performance characteristics for the second period are not consistent with the well model and, in response: determining, based on the second set of operating parameters, an updated skin factor; and determining, based on the updated skin factor (S2), an updated well model for the well.

Abstract: Techniques for developing a hydrocarbon well that include: determining a skin increase threshold; collecting historical production data for hydrocarbon wells; determining, based on the data, skin profiles for the wells; identifying, in response to changes in skin that exceed the threshold, wells as candidates for stimulation; for each of the candidate wells: determining an observed production rate; determining a predicted production rate that corresponds to a skin of zero; determining a cost of stimulation to remediate the well; determining, based on the observed and predicted production rates, a predicted increase in production attributable to stimulation; and determining, based on the cost of stimulation and the predicted increase, a marginal production cost for increased production; selecting, based on the marginal production costs of the candidate wells, a well to be stimulated; and conducting a stimulation of the well selected.

Abstract: A pressure bleed-off module for an oil well includes: an inlet receiving fluid from an annulus vent of the well; an outlet sending the received fluid to a kill valve of the well; and two paths coupled in parallel between the inlet and the outlet. Each path channels a flow of the received fluid from the inlet to the outlet and includes: a pressure relief valve dividing the path into an inlet side coupled to the inlet and an outlet side coupled to the outlet, opening when the pressure of the fluid in the inlet side exceeds a threshold, and closing when the inlet fluid pressure is below the threshold; pressure gauges measuring the inlet fluid pressure and the pressure of the fluid in the outlet side; a pressure recorder recording the measured inlet and outlet fluid pressures; and a sampling point for draining the fluid in the outlet side.

Abstract: Provided are techniques that include determining a first set of operating parameters for a hydrocarbon well for a first period; determining, based on the first set of operating parameters, a skin factor (S1); determining, based on the skin factor (S1), a well model for the well; determining, a second set of operating parameters for the well for a second period; determining, based on the second set of operating parameters, well performance characteristics for the second period that include: a well pressure and a production flowrate for the second period of time; determining that the well performance characteristics for the second period are not consistent with the well model and, in response: determining, based on the second set of operating parameters, an updated skin factor; and determining, based on the updated skin factor (S2), an updated well model for the well.